**Exhibit 99.3**

 

**MANAGEMENT’S DISCUSSION AND ANALYSIS**

 

This management’s discussion and analysis (“MD&A”) is ARC Resources Ltd. (“ARC” or the “Corporation”) management’s analysis of its financial performance and significant trends or external factors that may affect future performance.  It is dated February 10, 2011 and should be read in conjunction with the audited Consolidated Financial Statements as at and for the year ended December 31, 2010, the MD&A and the audited Consolidated Financial Statements as at and for the year ended December 31, 2009, the MD&A and the unaudited Consolidated Financial Statements for the periods ended March 31, 2010, June 30, 2010 and September 30, 2010 as well as ARC’s Annual Information Form that is filed on SEDAR at www.sedar.com.

 

The MD&A contains Non-GAAP measures and forward-looking statements and readers are cautioned that the MD&A should be read in conjunction with ARC’s disclosure under “Non-GAAP Measures” and “Forward-Looking Statements” included at the end of this MD&A.

 

**CORPORATE CONVERSION**

On December 31, 2010, ARC Energy Trust (the “Trust”) effectively completed its conversion to a dividend paying corporation from an income trust pursuant to a Plan of Arrangement (the “Arrangement”) under Section 193 of the Business Corporations Act (Alberta) involving, among others, the Trust, ARC Resources Ltd. and securityholders of the Trust and ARC. Pursuant to the Arrangement, holders (“unitholders”) of trust units (“trust units”) of the Trust received one common share (“common share”) of ARC for each trust unit.  In addition, holders of Series A exchangeable shares and Series B exchangeable shares (“Exchangeable Shares”) of the Corporation received 2.89162 common shares of ARC for each Exchangeable Share.  As a result of the Arrangement, on December 31, 2010 ARC had approximately 284.4 million common shares issued and outstanding.

 

The Common Shares of ARC trade on the Toronto Stock Exchange (the “TSX”) under the trading symbol ARX.  Beginning with the January 31, 2011 record date, shareholders of ARC will receive payments in the form of dividends.  Prior to the conversion of the Trust to a corporation on December 31, 2010, distributions were paid to unitholders.  Previous historical references to “unitholders”, “distributions” “trust units”, and “per unit” have now been replaced by “shareholders”, “dividends”, “common shares”, and “per share”, respectively, where applicable.

 

Despite the change in legal structure from a trust to a dividend paying corporation, ARC’s business activities and business strategy remain unchanged and all officers and directors remain the same.

 

**ABOUT ARC RESOURCES LTD.**

ARC, with a total capitalization of approximately $8 billion, is a mid-sized dividend****paying Canadian exploration and production company with near term growth prospects. ARC’s activities relate to the exploration, development and production of conventional oil and natural gas with an emphasis on the acquisition and development of properties with a large volume of hydrocarbons in place commonly referred to as “resource plays”.  Production from individual oil and natural gas wells naturally decline over time. In any one year, ARC approves a budget to drill new wells to firstly replace declines and potentially increase production. ARC was previously structured as a trust and converted to a corporate structure on December 31, 2010.  ARC will continue to operate as an oil and natural gas company, hiring and developing staff with expertise specific to ARC’s oil and natural gas operations. As of the end of 2010, ARC had approximately 500 employees with 300 professional and technical staff in the Calgary office and 200 individuals located in ARC’s operating areas in western Canada.

 

ARC is results focused with a goal to provide superior, long-term returns to shareholders through risk-managed value creation.  ARC takes a disciplined approach to capital allocation, deploying capital on projects to achieve this goal. Our staff uses their expertise to unlock additional reserves that will lead to higher future production through the exploration for and development of large oil and natural gas pools. Our main activities that support this objective are:

 

**1.****             ****Resource Plays** — Geological evaluation, acquisition, development and, if economically viable, subsequent production from lands and producing properties with large resource in place.

 

*ARC’s most significant resource plays include the Montney development at Dawson, northeast British Columbia, Ante Creek in northern Alberta and the Cardium formation at Pembina in central Alberta.  ARC’s 2011 budgeted capital expenditures are focused on the resource play development at Ante Creek and Pembina. Where applicable, enhanced oil recovery programs (“EOR programs”) are utilized to increase recoverability of reserves. ARC has non-operated interests in the Weyburn and Midale units in Saskatchewan where operators have implemented CO**2** injection programs to increase recoverable oil reserves.  ARC has completed the injection component of a CO**2** pilot program at Redwater in Alberta and is currently conducting a technical analysis of the results.*

 

1

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**2.****             ****Conventional Oil & Natural Gas Production** - Maximizing production while controlling operating costs on oil and natural gas wells located within ARC’s core producing areas in western Canada.  This may include the periodic acquisition and disposition of strategic producing and undeveloped properties to enhance current production, the rationalization of asset portfolios or the provision of potential future drilling locations and, if successful, additional production and reserves.  Current oil production is predominantly light and medium quality.

 

The following table highlights ARC’s production volume and reserve profile for the last five years:

 

**Table 1**

 
| ** **                            | ** ** | **2010**   | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------|------------|------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Production (boe/d)                    | ** ** | **73,954** |       | 63,538   |       | 65,126   |       | 62,723   |       | 63,056   |       |
| Proved plus probable reserves (mmboe) | ** ** | **487.4**  |       | 379.0    |       | 321.7    |       | 286.4    |       | 286.1    |       |

 

**Total Return to Shareholders**

ARC’s business plan has resulted in significant operational success and contributed to a trailing five year annualized return per share of eight per cent (Table 2).

 

**Table 2**

 
| **Total Returns ****(1)****($ per share except for per cent)** | ** ** | **Trailing One Year** | ** ** | **Trailing Three Year** | ** ** | **Trailing Five Year** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|
| Dividends per share                                                                                    | ** ** | **1.20**                        |       | 5.15                              |       | 10.15                            |       |
| Capital appreciation (depreciation) per share                                                          | ** ** | **5.47**                        |       | 5.01                              |       | (1.08                            | )          |
| Total return per share                                                                                 | ** ** | **34.8**                        | **%**      | 58.1                              | %          | 48.9                             | %          |
| Annualized total return per share                                                                      | ** ** | **34.8**                        | **%**      | 16.5                              | %          | 8.3                              | %          |
| S&P/TSX Exploration & Producers Index   annualized total return                           | ** ** | **12.5**                        | **%**      | 3.9                               | %          | 4.5                              | %          |

 

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(1)          Calculated as at December 31, 2010.

 

**Per Share Metrics**

ARC’s performance can be measured by its ability to grow both production and reserves. On a per share dividend adjusted basis, normalized production and reserves per share would have increased 15 per cent and 56 per cent, respectively from 2008 to 2010.

 

A key performance indicator for the future is production and reserves growth on a per share basis. From its 1996 inception, ARC has paid out $3.8 billion to shareholders and financed a large percentage of its acquisitions by issuing additional shares. As we look forward to 2011 and beyond, ARC’s goal is to fund both dividends and capital expenditures out of cash flow while accessing cash flow, equity, debt, or proceeds from property dispositions to finance growth capital expenditures or acquisitions. Debt will be used to fund capital to the extent it is prudent to do so while maintaining prudent debt levels. Debt levels at the end of 2010 were within our current target of under two times cash flow from operating activities and 20 per cent of total capitalization.

 

ARC provides returns to shareholders through both the potential for capital appreciation as production and reserves grow and through a dividend payment of $0.10 per share per month to its shareholders.

 

Table 3 details ARC’s normalized production, reserves and distributions per share/unit, with and without dividend adjustments, over the past three years:

 

**Table 3**

 
| **Per Share**                                            | ** ** | **2010** | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Normalized production, boe per share (1) (2)             | ** ** | **0.30** |       | 0.27     |       | 0.29     |       |
| Normalized reserves, boe per share (1) (3)               | ** ** | **1.80** |       | 1.57     |       | 1.42     |       |
| Dividends/distributions per unit                              | ** ** | **$**    | **1.20**   |     | $          | 1.28     |       | $ | 2.67 |   |
| Normalized production, dividend adjusted, boe per   share (4) | ** ** | **0.36** |       | 0.32     |       | 0.32     |       |
| Normalized reserves, dividend adjusted, boe per   share (4)   | ** ** | **2.31** |       | 1.90     |       | 1.58     |       |
|                                                               |            |          |            |          |            |          |            |  |  |  |

 

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(1)          Normalized indicates that all periods as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional shares were issued (or repurchased) at a period end price for the reserves per share calculation and at an annual average price for the production per share calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of per share values.

 

(2)          Production per share represents daily average production (boe) per thousand shares and is calculated based on daily average production divided by the normalized diluted common shares.

 

(3)          Reserves per share is calculated based on proved plus probable reserves (boe), as determined by ARC’s independent reserve evaluator solely at year-end, divided by period end shares outstanding.

 

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(4)          The dividend adjustment assumes that historical dividends from January 1, 2008 were reinvested back into ARC shares. This results in a reduction of the number of shares outstanding and, in turn, results in higher normalized production per share and normalized reserves per share.

 

**ECONOMIC ENVIRONMENT**

The global economy grew at an impressive rate of 4.8 per cent in 2010 with emerging markets leading the way at an estimated rate of 7.1 per cent (source: International Monetary Fund). Traditionally, changes in commodity prices have correlated with changes in economic growth.  Global trade has recovered significantly since the start of the U.S. recession in late 2007 and equity composites in Canada and the United States have rallied by 15 per cent from September 2010 to December 2010.  Equity growth was driven by strong corporate earnings and economic activity in the United States, the world’s largest economy, where high unemployment continues to be a key focus resulting in stimulus efforts through government spending and historic low interest rates.

 

Strong global economic activity and market demand resulted in oil prices averaging US$79.55 per barrel in 2010, a 28 per cent increase over 2009 levels.  China exhibited the largest growth in oil consumption of any country in the world, reaching total consumption of over 10 million barrels per day in December 2010, second only in oil consumption to the United States.  In 2010, the United States averaged 19.2 million barrels per day of oil consumption (source: International Energy Agency).

 

In North American markets, natural gas production levels continue to grow due to improving drilling techniques in tight shale and silt formations as well as land tenure commitments.  This has resulted in considerable benefit to North American consumers in providing an environmentally-friendly low cost fuel and has benefited natural gas producers who have harnessed these techniques to significantly increase their reserve base and generate profits through reduced cost structures. With added supply, however, natural gas prices have been depressed resulting in an oil to natural gas price ratio of approximately 18 times for 2010, significant deviation from the energy-equivalent six mcf of natural gas to one barrel of oil volumetric ratio.

 

**2010 and 2011 Guidance and Financial Highlights**

Table 4 is a summary of ARC’s 2010 and 2011 Guidance and a review of 2010 actual results:

 

**Table 4**

 
| ** **                                       | ** ** | **2010 Guidance**   | ** ** | **2010 Actual** | ** ** | **% Variance** | ** ** | **2011 Guidance** | ** ** |
|--------------------------------------------------|------------|--------------------------|------------|----------------------|------------|---------------------|------------|------------------------|------------|
| Production                                       | ** ** | ** **               | ** ** | ** **           |       |                |       |                   |       |
| Oil (bbls/d)                                     | ** ** | ** **               | ** ** | **27,341**           |       |                |       | 27,500 — 28,500   |       |
| NGLs (bbls/d)                                    | ** ** | ** **               | ** ** | **4,245**            |       |                |       | 4,000 — 4,800     |       |
| Natural Gas (mmcf/d)                             | ** ** | ** **               | ** ** | **254.2**            |       |                |       | 315 — 322         |       |
| Total (boe/d)                                    | ** ** | **72,500 — 74,500** | ** ** | **73,954**           |       | —              |       | 84,000 — 87,000   |       |
| Expenses ($/boe):                                | ** ** | ** **               | ** ** | ** **           |       |                |       |                   |       |
| Operating costs                                  | ** ** | **10.00**                | ** ** | **9.70**             |       | (3                  | )          | 9.40 — 9.70       |       |
| Transportation                                   | ** ** | **1.10**                 | ** ** | **1.10**             |       | —              |       | 1.10 — 1.20       |       |
| Cash general and administrative(1)               | ** ** | **2.90**                 | ** ** | **2.95**             |       | 10                  |       | 2.20 — 2.40       |       |
| Interest                                         | ** ** | **1.70**                 | ** ** | **1.57**             |       | (8                  | )          | 1.25 — 1.40       |       |
| Capital expenditures ($ millions)           | ** ** | **625**                  | ** ** | **591**              |       | (5                  | )          | 625                    |       |
| Annual weighted average common shares (millions) | ** ** | **264**                  | ** ** | **264**              |       | —              |       | 286                    |       |

 

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(1)          Cash G&A guidance for 2011 increased due to higher estimated cash payments expected under the RSU and PSU Plan resulting from an increase in both share price and the performance multiplier.

 

2010 full year actual results are in-line with the 2010 Guidance, with production at the high end of the Guidance range and operating costs and interest expense below Guidance due to disciplined cost management, lower electricity costs and lower than anticipated debt levels.

 

The 2011 Guidance provides shareholders with information on management’s expectations for results of operations.  Readers are cautioned that the 2011 Guidance may not be appropriate for other purposes.

 

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**2010 FOURTH QUARTER AND 2010 ANNUAL FINANCIAL AND OPERATIONAL RESULTS**

 

**Financial Highlights**

 

**Table 5**

 
| **(Cdn$ millions, except per share and volume** | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|-------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| **data)**                                                                     | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Cash flow from operating activities                                           | ** ** | **186.2**                                           |       | 143.2                                                |       | 30 | ** ** | **673.9** |   | 497.4 |   | 35 |   |
| Cash flow from operating activities per share (1)                             | ** ** | **0.66**                                            |       | 0.61                                                 |       | 8 | ** ** | **2.55** |   | 2.11 |   | 21 |   |
| Net income (loss)                                                             | ** ** | **(6.3**                                            | **)**      | 66.2                                                 |       | (110 | ) | **260.8** |   | 225.1 |   | 16 |   |
| Net income (loss) per share (1)                                               | ** ** | **(0.01**                                           | **)**      | 0.28                                                 |       | (104 | ) | **0.99** |   | 0.96 |   | 3 |   |
| Operating income                                                              | ** ** | **47.0**                                            |       | 59.5                                                 |       | (21 | ) | **219.6** |   | 179.1 |   | 23 |   |
| Operating income per share (1)                                                | ** ** | **0.17**                                            |       | 0.25                                                 |       | (34 | ) | **0.83** |   | 0.76 |   | 9 |   |
| Distributions per unit (2)                                                    | ** ** | **0.30**                                            |       | 0.30                                                 |       | — | ** ** | **1.20** |   | 1.28 |   | (6 | ) |
| Average daily production (boe/d) (3)                                          | ** ** | **84,686**                                          |       | 62,520                                               |       | 35 | ** ** | **73,954** |   | 63,538 |   | 16 |   |

 

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(1)          Per share amounts are based on the diluted common shares.

(2)          Based on number of trust units outstanding at each distribution record date.

(3)          Reported production amount is based on company interest before royalty burdens. Where applicable in this MD&A natural gas has been converted to barrels of oil equivalent (“boe”) based on 6 mcf:1 bbl. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading.

 

**Cash Flow from Operating Activities**

Cash flow from operating activities increased by 30 per cent in the fourth quarter of 2010 to $186.2 million from $143.2 million in the fourth quarter of 2009.  The increase was primarily attributed to a 35 per cent increase in production and a $21.7 million increase in realized gains on risk management contracts, partially offset by a decrease in natural gas prices and higher total operating costs.  Details of the change in cash flow from operating activities in the fourth quarter of 2009 to the fourth quarter of 2010 are presented in Table 6.

 

**Table 6**

 
| ** **                                        | ** ** | **($ millions)** | ** ** | **($ per share)** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|-----------------------------|------------|
| **Q4 2009 Cash flow from   Operating Activities** | ** ** | **143.2**             | ** ** | **0.60**                    | ** ** |
| Volume variance                                   |       | 98.8                  |       | 0.41                        |       |
| Price variance                                    |       | (48.1                 | )          | (0.20                       | )          |
| Cash gains on risk management contracts           |       | 21.7                  |       | 0.09                        |       |
| Royalties                                         |       | (1.4                  | )          | (0.01                       | )          |
| Expenses:                                         |       |                  |       |                        |       |
| Transportation                                    |       | (3.1                  | )          | (0.01                       | )          |
| Operating (1)                                     |       | (11.7                 | )          | (0.05                       | )          |
| General and administrative (1)                    |       | (4.4                  | )          | (0.02                       | )          |
| Interest                                          |       | (4.6                  | )          | (0.02                       | )          |
| Taxes                                             |       | —                |       | —                      |       |
| Realized foreign exchange gain                    |       | (0.9                  | )          | —                      |       |
| Weighted average shares                           |       | —                |       | (0.12                       | )          |
| Non-cash and other items (2)                      |       | (3.3                  | )          | (0.01                       | )          |
| **Q4 2010 Cash flow from   Operating Activities** | ** ** | **186.2**             | ** ** | **0.66**                    | ** ** |

 

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(1)          Excludes non-cash portion of RSU & PSU Plan expense recorded in operating and general and administrative costs.

(2)          Includes the changes in non-cash working capital and expenditures on site restoration and reclamation.

 

Year-to-date cash flow from operating activities increased by 35 per cent in 2010 to $673.9 million from $497.4 million in the comparable period of 2009. The increase was attributed to higher production volumes and commodity prices as well as an increase in realized gains on risk management contracts, partially offset by higher royalties and higher total operating costs. Details of the change in cash flow from operating activities from 2009 to 2010 are presented in Table 6a.

 

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**Table 6a**

 
| ** **                                         | ** ** | **($ millions)** | ** ** | **($ per share)** | ** ** |
|----------------------------------------------------|------------|-----------------------|------------|-----------------------------|------------|
| **YTD 2009 Cash flow from   Operating Activities** | ** ** | **497.4**             | ** ** | **2.11**                    | ** ** |
| Volume variance                                    |       | 160.4                 |       | 0.68                        |       |
| Price variance                                     |       | 75.1                  |       | 0.32                        |       |
| Cash gains on risk management contracts            |       | 46.0                  |       | 0.20                        |       |
| Royalties                                          |       | (45.0                 | )          | (0.20                       | )          |
| Expenses:                                          |       |                  |       |                        |       |
| Transportation                                     |       | (9.1                  | )          | (0.04                       | )          |
| Operating (1)                                      |       | (24.8                 | )          | (0.11                       | )          |
| General and administrative (1)                     |       | (22.3                 | )          | (0.09                       | )          |
| Interest                                           |       | (16.8                 | )          | (0.07                       | )          |
| Taxes                                              |       | 0.1                   |       | —                      |       |
| Realized foreign exchange gain                     |       | (1.0                  | )          | —                      |       |
| Weighted average shares                            |       | —                |       | (0.31                       | )          |
| Non-cash and other items (2)                       |       | 13.9                  |       | 0.06                        |       |
| **YTD 2010 Cash flow from   Operating Activities** | ** ** | **673.9**             | ** ** | **2.55**                    | ** ** |

 

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(1)          Excludes non-cash portion of RSU & PSU Plan expense recorded in operating and general and administrative costs.

(2)          Includes the changes in non-cash working capital and expenditures on site restoration and reclamation.

 

**2011 Cash Flow from Operating Activities Sensitivity**

 

Table 7 illustrates sensitivities on pre-hedged operating income items to operational and business environment changes and the resulting impact on cash flows from operating activities per share:

 

**Table 7**

 
| ** **                                             | ** ** | ** **     | ** ** | **Impact on Annual   Cash Flow from Operating   Activities ****(4)** | ** ** |
|--------------------------------------------------------|------------|----------------|------------|----------------------------------------------------------------------------------------------------|------------|
| ** **                                             | ** ** | **Assumption** | ** ** | **Change**                                                                                         | ** ** | **$/Share** | ** ** |
| **Business Environment**(1)                            |       |           |       |                                                                                               |       |   |   |
| Oil price (US$ WTI/bbl) (2)(3)                    |       | $              | 80.00      |                                                                                               | $          | 1.00 |   | 0.03 |   |
| Natural gas price (Cdn$ AECO/mcf) (2)(3)          |       | $              | 4.00       |                                                                                               | $          | 0.10 |   | 0.04 |   |
| Cdn$/US$ exchange rate (2)(3)(5)                  |       | 1.00           |       | $                                                                                                  | 0.01       |   | 0.03 |   |
| Interest rate on debt (2)                              |       | %              |  5.5  |                                                                                               | %          | 1.0 |   | 0.01 |   |
| **Operational**                                        |       |           |       |                                                                                               |       |   |   |   |
| Liquids production volume (bbl/d)                      |       | 33,000         |       | %                                                                                                  | 1.0        |   | 0.03 |   |
| Gas production volumes (mmcf/d)                        |       | 310            |       | %                                                                                                  | 1.0        |   | 0.02 |   |
| Operating expenses per boe                             |       | $              | 9.55       |                                                                                               | %          | 1.0 |   | 0.01 |   |
| Cash G&A and RSU & PSU expenses per   boe |       | $              | 2.30       |                                                                                               | %          | 10.0 |   | 0.03 |   |
|                                                        |            |                |            |                                                                                                    |            |  |  |  |  |  |  |

 

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| (1) | Calculations   are performed independently and may not be indicative of actual results that   would occur when multiple variables change at the same time.                                                                                                  |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | Prices   and rates are indicative of published forward prices and rates at the time of   this MD&A. The calculated impact on annual cash flow from operating   activities would only be applicable within a limited range of these amounts.             |
| (3) | Analysis   does not include the effect of hedging contracts.                                                                                                                                                                                                |
| (4) | Assumes   constant working capital.                                                                                                                                                                                                                         |
| (5) | Includes   impact of foreign exchange on crude oil prices that are presented in U.S.   dollars.  This amount does not include a foreign exchange impact   relating to natural gas prices as it is presented in Canadian dollars in this   sensitivity. |

 

**Net Income**

A net loss of $6.3 million was generated in the fourth quarter of 2010 ($0.01 per share), a $72.5 million decrease compared to net income of $66.2 million ($0.28 per share) in 2009.  The change from a net income position to a net loss position is primarily due to an unrealized loss on risk management contracts of $85.9 million ($64.4 million net of tax) in the fourth quarter of 2010 as compared to an unrealized gain on risk management contracts of $0.2 million ($0.2 million net of tax) in 2009.  ARC realized higher revenues, net of royalties, and realized risk management gains of $71 million, compared to the fourth quarter of 2009.  This increase was partially offset by higher transportation, operating, general and administrative, and interest expenses of $41.8 million.  In addition, net income was impacted by higher depletion, depreciation and accretion (“DD&A”) expense of $36.2 million from the fourth quarter of 2009 to the fourth quarter of 2010.

 

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For the full year, net income increased from $225.1 million in 2009 to $260.8 million in 2010.  The increase in net income of $35.7 million is due to higher revenues, net of royalties, and realized risk management gains of $236.5 million partially offset by higher transportation, operating, general and administrative, and interest expense of $90.9 million.  In addition, net income was impacted by the following non-cash items for the full year of 2010 relative to the full year in 2009:

 

·                  Higher DD&A expense of $74.7 million

·                  Lower unrealized foreign exchange gain of $43.2 million

·                  Higher unrealized gains on risk management contracts of $35.9 million

·                  Lower future income tax recovery of $27.2 million

 

**Operating income**

Operating income is a non-GAAP measure that adjusts net income by significant one-time items and items that are not indicative of operating performance that ARC believes reduces the comparability of ARC’s underlying financial performance between periods.  For the full year 2010, operating income was $244.1 million, a 35 per cent increase over $181.2 million in 2009.  For the fourth quarter of 2010, operating income fell by $11.3 million as increases in operating, general and administrative, interest expense, and DD&A offset the increase in higher revenues.

 

Table 8 summarizes ARC’s operating income:

 

**Table 8**

 
| ** **                                                           | ** ** | **Three Months Ended December 31** | ** ** | **Twelve Months Ended December 31** | ** ** |
|----------------------------------------------------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------|------------|
| **($ millions) **                                          | ** ** | **2010**                                               | ** ** | **2009**                                                | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Net income (loss)                                                    | ** ** | **(6.3**                                               | **)**      | 66.2                                                    |       | (110 | ) | **260.8** |   | 225.1 |   | 16 |   |
| Add back (or deduct):                                                | ** ** | ** **                                             | ** ** | ** **                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Unrealized (gains) losses on risk management   contracts, net of tax | ** ** | **64.4**                                               |       | (0.2                                                    | )          | — | ** ** | **(21.2** | **)** | 5.8 |   | (466 | ) |
| Unrealized (gains) losses on foreign exchange, net   of tax          | ** ** | **(7.7**                                               | **)**      | (4.3                                                    | )          | 79 | ** ** | **4.5** |   | (49.7 | ) | 109 |   |
| Operating income                                                     | ** ** | **50.4**                                               |       | 61.7                                                    |       | (18 | ) | **244.1** |   | 181.2 |   | 35 |   |

 

**Production**

Production volumes averaged 84,686 boe per day in fourth quarter of 2010 compared to 62,520 boe per day in the same period of 2009 as detailed in Table 9. Full year 2010 saw a 16 per cent increase in production volumes. The increase in both the fourth quarter 2010 and full year 2010 production is a result of the new gas plant at Dawson coming on-stream in the second quarter of 2010 and operating above its original design capacity of 60 mmcf per day, the Storm acquisition that added approximately 8,800 boe per day for the quarter and approximately 3,400 boe per day for the full year 2010, the acquisition of assets in Ante Creek that closed in late 2009 and new wells brought on production during the year.

 

**Table 9**

 
| ** **                                    | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|-----------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| **Production**                                | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Light and medium crude oil (bbl/d)            | ** ** | **26,455**                                          |       | 26,299                                               |       | 1 | ** ** | **26,390** |   | 26,423 |   | — |   |
| Heavy oil (bbl/d)                             | ** ** | **962**                                             |       | 1,116                                                |       | (14 | ) | **951** |   | 1,086 |   | (12 | ) |
| Natural gas (mmcf/d)                          | ** ** | **311.5**                                           |       | 189.0                                                |       | 65 | ** ** | **254.2** |   | 194.0 |   | 31 |   |
| Natural gas liquids (“NGL”) (bbl/d) | ** ** | **5,355**                                           |       | 3,597                                                |       | 49 | ** ** | **4,245** |   | 3,689 |   | 15 |   |
| Total production (boe/d) (1)                  | ** ** | **84,686**                                          |       | 62,520                                               |       | 35 | ** ** | **73,954** |   | 63,538 |   | 16 |   |
| % Natural gas production                      | ** ** | **61**                                              |       | 50                                                   |       | 22 | ** ** | **57** |   | 51 |   | 12 |   |
| % Crude oil and liquids production            | ** ** | **39**                                              |       | 50                                                   |       | (22 | ) | **43** |   | 49 |   | (12 | ) |

 

----

(1)          Reported production for a period may include minor adjustments from previous production periods.

 

ARC’s crude oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than four per cent of the total. Fourth quarter and full year 2010 light and medium crude oil production remained relatively unchanged from the prior year.  ARC has redirected its focus to exploiting oil and liquids rich properties for 2011 and has reflected this strategy in its 2011 capital budget in order to take advantage of stronger oil prices relative to natural gas.

 

Natural gas production was 311.5 mmcf per day in the fourth quarter of 2010, an increase of 65 per cent from the 189 mmcf per day produced in the fourth quarter of 2009.  For the full year 2010, natural gas production increased 31 per cent from full year 2009.

 

6

----

 

During the fourth quarter of 2010, ARC drilled 40 gross wells (39 net wells) on operated properties consisting of 30 gross oil wells and 10 gross natural gas wells with a 100 per cent success rate.  For the full year 2010, ARC drilled 176 gross wells (165 net wells) on operated properties consisting of 85 gross oil wells and 91 gross natural gas wells with a 100 per cent success rate.  A total of 182 wells, excluding acquisitions, were brought on production during 2010.

 

Looking forward, ARC expects that 2011 full year production will average approximately 84,000 to 87,000 boe per day, that it will drill a total of approximately 166 gross (148 net) wells on operated properties and participate in an additional 83 gross wells (10 net) to be drilled on non-operated properties.

 

Tables 10 and 10a summarize ARC’s production by core area:

 

**Table 10**

 
| ** **                      | ** ** | **Three Months Ended December 31, 2010** | ** ** | **Three Months Ended December 31, 2009** | ** ** |
|---------------------------------|------------|-------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| **Production**                  | ** ** | **Total**                                                         | ** ** | **Oil**                                                           | ** ** | **Gas** | ** ** | **NGL** | ** ** | **Total** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **NGL** | ** ** |
| **Core Area ****(1)** | ** ** | **(boe/d)**                                                       | ** ** | **(bbl/d)**                                                       | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** | **(boe/d)** | ** ** | **(bbl/d)** | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** |
| Central AB                      | ** ** | **6,411**                                                         | ** ** | **1,431**                                                         | ** ** | **24.4** | ** ** | **917** |   | 6,674 |   | 1,270 |   | 26.3 |   | 1,010 |   |
| N.E. BC & N.W. AB      | ** ** | **33,816**                                                        | ** ** | **699**                                                           | ** ** | **185.9** | ** ** | **2,146** |   | 13,562 |   | 695 |   | 73.2 |   | 668 |   |
| Northern AB                     | ** ** | **12,590**                                                        | ** ** | **4,726**                                                         | ** ** | **40.4** | ** ** | **1,128** |   | 9,003 |   | 4,169 |   | 24.4 |   | 773 |   |
| Pembina                         | ** ** | **9,619**                                                         | ** ** | **6,237**                                                         | ** ** | **14.6** | ** ** | **942** |   | 9,387 |   | 5,645 |   | 17.3 |   | 852 |   |
| Redwater                        | ** ** | **4,194**                                                         | ** ** | **3,826**                                                         | ** ** | **1.6** | ** ** | **107** |   | 4,232 |   | 3,880 |   | 1.1 |   | 174 |   |
| S.E. AB & S.W. Sask.   | ** ** | **8,293**                                                         | ** ** | **1,024**                                                         | ** ** | **43.5** | ** ** | **12** |   | 8,599 |   | 1,059 |   | 45.2 |   | 13 |   |
| S.E. Sask. & MB        | ** ** | **9,763**                                                         | ** ** | **9,474**                                                         | ** ** | **1.1** | ** ** | **103** |   | 11,063 |   | 10,697 |   | 1.5 |   | 107 |   |
| **Total**                       | ** ** | **84,686**                                                        | ** ** | **27,417**                                                        | ** ** | **311.5** | ** ** | **5,355** |   | 62,520 |   | 27,415 |   | 189.0 |   | 3,597 |   |

 

**Table 10a**

 
| ** **                      | ** ** | **Year Ended December 31, 2010** | ** ** | **Year Ended December 31, 2009** | ** ** |
|---------------------------------|------------|------------------------------------------------------|------------|------------------------------------------------------|------------|
| **Production**                  | ** ** | **Total**                                            | ** ** | **Oil**                                              | ** ** | **Gas** | ** ** | **NGL** | ** ** | **Total** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **NGL** | ** ** |
| **Core Area ****(1)** | ** ** | **(boe/d)**                                          | ** ** | **(bbl/d)**                                          | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** | **(boe/d)** | ** ** | **(bbl/d)** | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** |
| Central AB                      | ** ** | **6,555**                                            | ** ** | **1,372**                                            | ** ** | **25.2** | ** ** | **981** |   | 6,984 |   | 1,279 |   | 27.7 |   | 1,083 |   |
| N.E. BC & N.W. AB      | ** ** | **23,656**                                           | ** ** | **686**                                              | ** ** | **130.0** | ** ** | **1,297** |   | 13,794 |   | 715 |   | 74.4 |   | 672 |   |
| Northern AB                     | ** ** | **11,541**                                           | ** ** | **4,598**                                            | ** ** | **35.9** | ** ** | **968** |   | 9,004 |   | 4,096 |   | 24.5 |   | 821 |   |
| Pembina                         | ** ** | **9,143**                                            | ** ** | **5,706**                                            | ** ** | **16.2** | ** ** | **739** |   | 9,408 |   | 5,629 |   | 17.9 |   | 800 |   |
| Redwater                        | ** ** | **4,179**                                            | ** ** | **3,823**                                            | ** ** | **1.3** | ** ** | **138** |   | 4,150 |   | 3,783 |   | 1.1 |   | 178 |   |
| S.E. AB & S.W. Sask.   | ** ** | **8,414**                                            | ** ** | **1,037**                                            | ** ** | **44.2** | ** ** | **12** |   | 8,841 |   | 1,027 |   | 46.9 |   | 13 |   |
| S.E. Sask. & MB        | ** ** | **10,466**                                           | ** ** | **10,119**                                           | ** ** | **1.4** | ** ** | **110** |   | 11,357 |   | 10,980 |   | 1.5 |   | 122 |   |
| **Total**                       | ** ** | **73,954**                                           | ** ** | **27,341**                                           | ** ** | **254.2** | ** ** | **4,245** |   | 63,538 |   | 27,509 |   | 194.0 |   | 3,689 |   |

 

----

(1)          Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is northwest, S.E. is southeast and S.W. is southwest.

 

**Revenue**

Revenue was $329.3 million in the fourth quarter of 2010, an increase of $50.7 million over 2009 revenue of $278.6 million primarily related to the increase in production volumes.  For the full year, revenue increased $235.5 million from $978.2 million in 2009 to $1,213.7 million in 2010.

 

A breakdown of revenue is outlined in Table 11:

 

**Table 11**

 
| **Revenue**             | ** ** | **Three Months Ended December 31** | ** ** | **Twelve Months Ended December 31** | ** ** |
|-------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------|------------|
| **($ millions)**   | ** ** | **2010**                                               | ** ** | **2009**                                                | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Oil revenue             | ** ** | **192.0**                                              |       | 183.2                                                   |       | 5 | ** ** | **737.0** |   | 625.0 |   | 18 |   |
| Natural gas revenue     | ** ** | **109.6**                                              |       | 79.7                                                    |       | 38 | ** ** | **391.0** |   | 296.0 |   | 32 |   |
| NGL revenue             | ** ** | **27.1**                                               |       | 15.3                                                    |       | 77 | ** ** | **83.6** |   | 54.8 |   | 53 |   |
| Total commodity revenue | ** ** | **328.7**                                              |       | 278.2                                                   |       | 18 | ** ** | **1,211.6** |   | 975.8 |   | 24 |   |
| Other revenue           | ** ** | **0.6**                                                |       | 0.4                                                     |       | 50 | ** ** | **2.1** |   | 2.4 |   | (12 | ) |
| Total revenue           | ** ** | **329.3**                                              |       | 278.6                                                   |       | 18 | ** ** | **1,213.7** |   | 978.2 |   | 24 |   |

 

7

----

 

**Commodity Prices Prior to Hedging**

 

**Table 12**

 
| ** **                                   | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|----------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                   | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| **Average Benchmark Prices**                 | ** ** | ** **                                          | ** ** | ** **                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| AECO gas ($/mcf) (1)                         | ** ** | **3.58**                                            |       | 4.23                                                 |       | (15 | ) | **4.12** |   | 4.13 |   | — |   |
| WTI oil (US$/bbl) (2)                        | ** ** | **85.18**                                           |       | 76.17                                                |       | 12 | ** ** | **79.55** |   | 61.93 |   | 28 |   |
| Cdn$ / US$ exchange rate           | ** ** | **1.01**                                            |       | 1.06                                                 |       | (5 | ) | **1.03** |   | 1.13 |   | (9 | ) |
| WTI oil (Cdn$/bbl)                           | ** ** | **86.26**                                           |       | 80.46                                                |       | 7 | ** ** | **81.87** |   | 69.70 |   | 17 |   |
| **ARC Realized Prices Prior to   Hedging**   | ** ** | ** **                                          | ** ** | ** **                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil ($/bbl)                                  | ** ** | **76.08**                                           |       | 72.61                                                |       | 5 | ** ** | **73.85** |   | 62.24 |   | 19 |   |
| Natural gas ($/mcf)                          | ** ** | **3.83**                                            |       | 4.58                                                 |       | (16 | ) | **4.21** |   | 4.18 |   | 1 |   |
| NGL ($/bbl)                                  | ** ** | **55.10**                                           |       | 46.12                                                |       | 19 | ** ** | **53.98** |   | 40.67 |   | 33 |   |
| Total commodity price before hedging ($/boe) | ** ** | **42.18**                                           |       | 48.35                                                |       | (13 | ) | **44.88** |   | 42.07 |   | 7 |   |
| Other revenue ($/boe)                        | ** ** | **0.08**                                            |       | 0.07                                                 |       | 14 | ** ** | **0.08** |   | 0.10 |   | (20 | ) |
| Total revenue before hedging****($/boe)      | ** ** | **42.26**                                           |       | 48.42                                                |       | (13 | ) | **44.96** |   | 42.17 |   | 7 |   |

 

----

(1)          Represents the AECO monthly posting.

(2)          WTI represents posting price of West Texas Intermediate oil.

 

Prior to hedging activities, ARC’s weighted average commodity price was $42.18 per boe in the fourth quarter of 2010, a decrease of 13 per cent as compared to $48.35 per boe in the fourth quarter of 2009.  The decrease in the weighted average realized commodity price is due to a decrease in natural gas prices coupled with the significant increase in the level of natural gas production while maintaining a constant level of liquids production. This has resulted in natural gas production contributing only 33 per cent of total revenue despite contributing 61 per cent to total production for the fourth quarter of 2010, compared to 29 per cent of total revenue and 50 per cent to total production in the fourth quarter of 2009.  For the full year 2010, the weighted average commodity price increased seven per cent to $44.96 per boe.  While ARC’s realized oil price increased 19 per cent, ARC’s realized natural gas price remained unchanged from 2009 to 2010.

 

Oil prices increased throughout 2010, with WTI increasing 28 per cent from 2009 to 2010.  The increase continued in the fourth quarter of 2010 with WTI averaging US$85.18 per barrel compared to US$76.17 per barrel for the fourth quarter of 2009. The outlook on oil prices remains positive as the global economy continues to recover.  Actual realized oil prices lagged behind the gain in WTI as a result of the strengthening of the Canadian dollar compared to the U.S. dollar.  The realized price for ARC’s oil, before hedging, was $76.08 per barrel, a five per cent increase over the fourth quarter 2009 realized price of $72.61 per barrel.

 

AECO monthly posted natural gas prices, the benchmark from which ARC derives the majority of its gas sales, decreased by 15 per cent in the fourth quarter of 2010 to $3.58 per mcf compared to $4.23 per mcf in the fourth quarter of 2009. ARC’s realized gas price, before hedging, decreased by 16 per cent to $3.83 per mcf compared to $4.58 per mcf in the fourth quarter of 2009. Despite sustained cold weather in North America, gas prices continue to be depressed, with ARC’s realized gas price rising marginally from $3.79 per mcf in the third quarter of 2010 to $3.83 per mcf in the fourth quarter of 2010.  The outlook for natural gas prices remains weak with United States gas production up approximately four bcf per day or eight per cent over 2009 and with North American storage levels remaining at near record highs for this time of year. Using the forward curve for natural gas prices as an indicator, AECO prices are expected to range from $3.50 per mcf to $4.50 per mcf for the first quarter of 2011.  ARC’s realized gas price is based on its natural gas sales portfolio consisting of sales priced at the AECO monthly index, the AECO daily spot market, eastern and midwest United States markets and a portion to aggregators.

 

**Risk Management and Hedging Activities**

ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of cash flows, and to protect acquisition and development economics.

 

Gains or losses on risk management contracts comprise realized and unrealized gains or losses that do not meet the accounting definition requirements of an effective hedge, even though ARC considers all risk management contracts to be effective economic hedges. Accordingly, gains and losses on such contracts are shown as a separate category in the Consolidated Statements of Income and Deficit.

 

During the fourth quarter of 2010, ARC realized a gain of $20 million on its risk management contracts. The largest contributor was a $16.9 million gain on ARC’s natural gas swaps and natural gas basis swap contracts.  For the full year 2010, ARC realized a gain of $65.4 million on its risk management contracts with $50.2 million arising from ARC’s natural gas swaps and natural gas basis swap contracts.

 

8

----

 

In addition, ARC recorded an $85.9 million unrealized mark-to-market loss on its risk management contracts in the fourth quarter of 2010, resulting in a net fair value gain of $24.6 million at December 31, 2010. The net loss position is primarily attributed to ARC’s WTI crude oil contracts, as the December 31, 2010 forward outlook on WTI crude oil prices strengthened from September 30, 2010.  The fair value of risk management contracts represent the expected market price to buy out ARC’s contracts as of December 31, 2010 and may differ from what will eventually be realized.  For the full year 2010, ARC recorded an unrealized gain of $28.2 million primarily as a result of an $85.2 million unrealized gain on natural gas risk management contracts due to the declining outlook on forward natural gas prices and a $59.9 million unrealized loss on crude oil contracts due to the strengthening of forward crude oil prices.

 

Table 13 summarizes the total (loss) gain on risk management contracts for the fourth quarter of 2010 compared to the same period in 2009:

 

**Table 13**

 
| **Risk Management Contracts****($ millions)** | ** ** | **Crude   Oil &   Liquids** | ** ** | **Natural   Gas** | ** ** | **Foreign   Currency** | ** ** | **Power** | ** ** | **Interest** | ** ** | **Q4 2010********Total** | ** ** | **Q4 2009    Total** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------|------------|-------------------|------------|------------------------|------------|-----------|------------|--------------|------------|-------------------------------|------------|--------------------------------|------------|
| Realized cash gain on contracts (1)                          |       | 2.6                                  |       | 16.9              |       | 0.5                    |       | —    |       | —       | ** ** | **20.0**                      |       | (1.7                           | )          |
| Unrealized (loss) gain on contracts (2)                      |       | (67.9                                | )          | (17.3             | )          | (1.2                   | )          | 0.6       |       | (0.1         | )          | **(85.9**                     | **)**      | 0.2                            |       |
| **Total (loss) gain on risk   management contracts**         |       | (65.3                                | )          | (0.4              | )          | (0.7                   | )          | 0.6       |       | (0.1         | )          | **(65.9**                     | **)**      | (1.5                           | )          |

 

----

(1)          Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts.

(2)          The unrealized (loss) gain on contracts represents the change in fair value of the contracts during the period.

 

Table 13a summarizes the total (loss) gain on risk management contracts for 2010 compared to 2009:

 

**Table 13a**

 
| **Risk Management Contracts****($ millions)** | ** ** | **Crude   Oil &   Liquids** | ** ** | **Natural   Gas** | ** ** | **Foreign   Currency** | ** ** | **Power** | ** ** | **Interest** | ** ** | **YTD 2010******** Total** | ** ** | **YTD 2009    Total** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------|------------|-------------------|------------|------------------------|------------|-----------|------------|--------------|------------|--------------------------------------|------------|---------------------------------|------------|
| Realized cash gain on contracts (1)                          |       | 9.1                                  |       | 50.2              |       | 5.7                    |       | 0.4       |       | —       | ** ** | **65.4**                             |       | 19.4                            |       |
| Unrealized (loss) gain on contracts (2)                      |       | (59.9                                | )          | 85.2              |       | (0.8                   | )          | 3.8       |       | (0.1         | )          | **28.2**                             |       | (7.7                            | )          |
| **Total (loss) gain on risk   management contracts**         |       | (50.8                                | )          | 135.4             |       | 4.9                    |       | 4.2       |       | (0.1         | )          | **93.6**                             |       | 11.7                            |       |

 

----

(1)          Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts.

(2)          The unrealized gain (loss) on contracts represents the change in fair value of the contracts during the period.

 

ARC is mitigating the weak outlook on natural gas prices by protecting the selling price on 128 mmcf per day of natural gas for 2011 at $5.85 per mcf. On the liquids side, ARC has protected 20,000 barrels of oil per day for 2011 at a floor price of US$84.30 per barrel on approximately 60 per cent of current liquids production.  ARC currently limits the amount of total forecast production that can be hedged to a maximum 55 per cent over the next two years with the remaining 45 per cent of production being sold at market prices.  In addition, ARC’s hedging policy allows for further hedging on volumes associated with new production arising from specific capital projects and acquisitions at the discretion of the Board.  The following table is a summary of ARC’s positions for crude oil and natural gas as at December 31, 2010.

 

9

----

 

**Table 14**

 
| **Hedge Positions   As at December 31, 2010 ****(1)** | ** ** | **2011**    | ** ** | **2012**    | ** ** |
|-------------------------------------------------------------------------------------|------------|-------------|------------|-------------|------------|
| **Crude Oil ****(2)**                                                     | ** ** | **US$/bbl** | ** ** | **bbl/day** | ** ** | **US$/bbl** | ** ** | **bbl/day** | ** ** |
| Sold Call                                                                           |       | 89.30       |       | 20,000      |       | 90.00 |   | 16,000 |   |
| ***Bought Put***                                                                    | ** ** | **84.30**   | ** ** | **20,000**  | ** ** | **90.00** | ** ** | **16,000** | ** ** |
| Sold Put                                                                            |       | 60.89       |       | 12,000      |       | 60.00 |   | 5,000 |   |

 
| **Natural Gas** | ** ** | **Cdn$/GJ** | ** ** | **GJ/day**  | ** ** | **Cdn$/GJ** | ** ** | **GJ/day** | ** ** |
|----------------------|------------|-------------|------------|-------------|------------|-------------|------------|------------|------------|
| ***Swap***           | ** ** | **5.54**    | ** ** | **135,000** | ** ** | **4.26**    | ** ** | **21,101** | ** ** |

 

----

| (1) | The   prices and volumes noted above represent averages for several contracts and   the average price for the portfolio of options listed above does not have the   same payoff profile as the individual option contracts. Viewing the average   price of a group of options is purely for indicative purposes. The natural   gas price shown translates all NYMEX positions to an AECO equivalent price   based on offsetting basis positions and the quarter end exchange rate.      |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | For   2011 and 2012, all put positions settle against the monthly average WTI   price, providing protection against monthly volatility; where disclosed in the   hedge note, calls have been sold against either the monthly average or the   annual average WTI price, in which case ARC will only have a negative   settlement if prices average above the strike price for an entire year   providing ARC with greater potential upside price participation for   individual months. |

 

 

To accurately analyze ARC’s hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.   The following provides examples of how Table 14 can be interpreted for approximate values for the first quarter of 2011:

 

·                  If the market price exceeds $89.30 per barrel, ARC will receive $89.30 per barrel on 20,000 barrels per day.

·                  If the market price is between $84.30 per barrel and $89.30 per barrel, ARC will receive the market price on 20,000 barrels per day.

·                  If the market price is between $60.89 per barrel and $84.30 per barrel, ARC will receive $84.30 per barrel on 20,000 barrels per day.

·                  If the market price is below $60.89 per barrel, ARC will receive $84.30 per barrel less the difference between $60.89 per barrel and the market price on 20,000 barrels per day.  For example, if the market price is at $55 per barrel, ARC will receive $78.41 on 12,000 barrels per day and $84.30 on 8,000 barrels per day.

 

**Operating Netbacks**

ARC’s operating netback, before realized hedging gains and losses, was $26.14 per boe in the fourth quarter of 2010 compared to $29.65 per boe in the same period of 2009.

 

ARC’s fourth quarter 2010 netback after realized hedging gains and losses, was $28.64 per boe, a two per cent decrease from the same period in 2009. The 2010 netback includes gains recorded on ARC’s crude oil and natural gas risk management contracts during the quarter of $2.50 per boe compared to a loss of $0.42 per boe recorded for the same period in 2009.

 

The components of operating netbacks are summarized in Tables 15 and 15a:

 

**Table 15**

 
| **Netbacks   ($ per boe)**                  | ** ** | **Crude Oil   ($/bbl)** | ** ** | **Heavy Oil   ($/bbl)** | ** ** | **Gas   ($/mcf)** | ** ** | **NGL   ($/bbl)** | ** ** | **Q4 2010   Total   ($/boe)** | ** ** | **Q4 2009   Total   ($/boe)** | ** ** |
|-------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-------------------|------------|-------------------|------------|------------------------------------|------------|------------------------------------|------------|
| Weighted average sales price                          |       | 76.54                        |       | 63.29                        |       | 3.83              |       | 55.10             | ** ** | **42.18**                          |       | 48.35                              |       |
| Other revenue                                         |       | —                       |       | —                       |       | —            |       | —            | ** ** | **0.08**                           |       | 0.07                               |       |
| Total revenue                                         |       | 76.54                        |       | 63.29                        |       | 3.83              |       | 55.10             | ** ** | **42.26**                          |       | 48.42                              |       |
| Royalties                                             |       | (12.50                       | )          | (6.03                        | )          | (0.28             | )          | (16.09            | )          | **(6.03**                          | **)**      | (7.94                              | )          |
| Transportation                                        |       | (0.26                        | )          | (0.66                        | )          | (0.28             | )          | —            | ** ** | **(1.08**                          | **)**      | (0.92                              | )          |
| Operating costs (1)                                   |       | (15.32                       | )          | (16.14                       | )          | (0.98             | )          | (7.38             | )          | **(9.01**                          | **)**      | (9.91                              | )          |
| Netback prior to hedging                              |       | 48.46                        |       | 40.46                        |       | 2.29              |       | 31.63             | ** ** | **26.14**                          |       | 29.65                              |       |
| Realized gain (loss) on risk management contracts (2) |       | 1.06                         |       | —                       |       | 0.59              |       | —            | ** ** | **2.50**                           |       | (0.42                              | )          |
| Netback after hedging                                 |       | 49.52                        |       | 40.46                        |       | 2.88              |       | 31.63             | ** ** | **28.64**                          |       | 29.23                              |       |

 

10

----

 

**Table 15a**

 
| **Netbacks   ($ per boe)**           | ** ** | **Crude Oil   ($/bbl)** | ** ** | **Heavy Oil   ($/bbl)** | ** ** | **Gas   ($/mcf)** | ** ** | **NGL   ($/bbl)** | ** ** | **2010   Total   ($/boe)** | ** ** | **2009 Total   ($/boe)** | ** ** |
|------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-------------------|------------|-------------------|------------|----------------------------|------------|-------------------------------|------------|
| Weighted average sales price                   |       | 74.24                        |       | 64.07                        |       | 4.21              |       | 53.98             | ** ** | **44.88**                  |       | 42.07                         |       |
| Other revenue                                  |       | —                       |       | —                       |       | —            |       | —            | ** ** | **0.08**                   |       | 0.10                          |       |
| Total revenue                                  |       | 74.24                        |       | 64.07                        |       | 4.21              |       | 53.98             | ** ** | **44.96**                  |       | 42.17                         |       |
| Royalties                                      |       | (12.50                       | )          | (7.39                        | )          | (0.47             | )          | (16.77            | )          | **(7.14**                  | **)**      | (6.37                         | )          |
| Transportation                                 |       | (0.28                        | )          | (0.99                        | )          | (0.29             | )          | —            | ** ** | **(1.10**                  | **)**      | (0.89                         | )          |
| Operating costs (1)                            |       | (13.94                       | )          | (14.39                       | )          | (1.18             | )          | (8.47             | )          | **(9.70**                  | **)**      | (10.19                        | )          |
| Netback prior to hedging                       |       | 47.52                        |       | 41.30                        |       | 2.27              |       | 28.74             | ** ** | **27.02**                  |       | 24.72                         |       |
| Realized gain on risk management contracts (2) |       | 0.95                         |       | —                       |       | 0.54              |       | —            | ** ** | **2.20**                   |       | 0.54                          |       |
| Netback after hedging                          |       | 48.47                        |       | 41.30                        |       | 2.81              |       | 28.74             | ** ** | **29.22**                  |       | 25.26                         |       |

 

----

| (1) | Operating   expenses are composed of direct costs incurred to operate oil and gas wells.   A number of assumptions have been made in allocating these costs between oil,   heavy oil, natural gas and natural gas liquids production. |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | Realized   gain (loss) on risk management contracts includes the settlement amounts for   crude oil and natural gas contracts. Foreign exchange and power contracts are   excluded from the netback calculation.                      |

 

Royalties as a percentage of pre-hedged commodity revenue, net of transportation, decreased from 16.7 per cent ($7.94 per boe) in the fourth quarter of 2009 to 14.6 per cent ($6.03 per boe) in 2010.  The decrease in the royalty rate is primarily due to the change in production profile, with higher production at properties with lower royalty rates relative to ARC’s corporate average royalty rate.  ARC has been capitalizing on incentives from the Alberta and British Columbia (“BC”) governments for new wells which allow for a five per cent and two per cent royalty rate, respectively.  In addition, ARC has also received deep gas drilling credits in BC in 2010 which have been applied against royalties.

 

Royalty rates in the other western provinces vary with production levels and price but to a lesser extent than Alberta royalty rates.  Table 16 estimates the royalties applicable to production from ARC’s properties at various price levels for 2011 prior to any provincial incentive programs.

 

**Table 16**

 
| **Edmonton posted oil (Cdn$/bbl) ****(1)****AECO natural gas (Cdn$/mcf) ****(1)** | ** ** | **$70   $3.50** | ** ** | **$70   $4.50** | ** ** | **$80   $3.50** | ** ** | **$80   $4.50** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|-----------------|------------|-----------------|------------|
| Alberta royalty rate                                                                                                      |       | 13.8            | %          | 14.5            | %          | 15.6            | %          | 16.2            | %          |
| Saskatchewan royalty rate (2)                                                                                             |       | 18.5            | %          | 18.1            | %          | 18.6            | %          | 18.3            | %          |
| British Columbia royalty rate (2)                                                                                         |       | 15.4            | %          | 18.2            | %          | 15.4            | %          | 18.2            | %          |
| Manitoba royalty rate (2)                                                                                                 |       | 12.5            | %          | 12.5            | %          | 12.5            | %          | 12.5            | %          |
| **Total Corporate Royalty Rate**                                                                                          | ** ** | **13.7**        | **%**      | **14.9**        | **%**      | **14.8**        | **%**      | **15.8**        | **%**      |

 

----

(1)          Before quality differentials.

(2)          Royalty rate includes Crown, freehold and gross override royalties for all jurisdictions in which ARC operates.

 

Following the implementation of the Alberta Royalty Framework (“ARF”) on January 1, 2009, the Alberta government introduced certain transitional rates and incentive programs to provide royalty relief to producers and to encourage continued drilling activity in the province. ARC will be eligible for the Alberta programs assuming the necessary criteria are met and required elections are filed. The drilling credit program applies to new wells drilled between April 1, 2009 and March 31, 2011. As at December 31, 2010, ARC has received credits of $11.2 million and estimates it will generate approximately $14.4 million in credits over the life of the program based on forward-looking prices. ARC is automatically eligible for the reduced royalty rate incentive on new production for wells coming on production between April 1, 2009 and March 31, 2011. These wells will receive a crown royalty rate of five per cent subject to certain production limits.  These changes will come into effect January 1, 2011.

 

Operating costs decreased to $9.01 per boe in the fourth quarter of 2010 compared to $9.91 per boe in 2009.  The decrease is attributable to the new production from the Dawson gas plant coming on stream at operating cost levels significantly below the corporate average and to lower operating costs relative to the corporate average of the Parkland field which accounted for approximately 85 per cent of the volume acquired through the Storm acquisition.

 

11

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**General and Administrative (“G&A”) Expenses and Long-term Incentive Compensation**

G&A, prior to the Restricted Share Unit and Performance Share Unit Plan (“RSU & PSU Plan”) expense and net of overhead recoveries on operated properties, increased 51 per cent from $9.9 million in the fourth quarter of 2009 to $14.9 million in 2010.  The same increase also occurred for the full year 2010, with Cash G&A expenses before RSU & PSU Plan increasing 45 per cent to $59.1 million.  The increase in G&A for both the fourth quarter 2010 and the full year 2010 is mainly due to higher compensation levels associated with both increased staffing levels required to execute ARC’s growth prospects and stronger performance metrics on ARC’s key performance indicators.  Annual compensation expenses also increased as ARC’s Board of Directors approved a $2.8 million special performance bonus to staff in recognition of exceptional 2009 results.  In addition, ARC incurred an increase in rent expense due to the relocation of ARC’s head office as well as higher legal and consulting expenses related to the conversion from a trust to a corporation.  These increases to G&A were partially offset by higher operating recoveries from ARC’s partners due to a larger capital program.

 

Table 17 is a breakdown of G&A and incentive compensation expense under the RSU & PSU Plan:

 

**Table 17**

 
| ** **                                                                                                           | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| **G&A and Incentive Compensation Expense   ($ millions except per boe)** | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **%   Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **%   Change** | ** ** |
| G&A expenses                                                                                                     | ** ** | **19.2**                                            |       | 14.0                                                 |       | 37 | ** ** | **75.0** |   | 56.1 |   | 34 |   |
| Operating recoveries                                                                                                 | ** ** | **(4.3**                                            | **)**      | (4.1                                                 | )          | 5 | ** ** | **(15.9** | **)** | (15.4 | ) | 3 |   |
| Cash G&A expenses before RSU & PSU   Plan                                                               | ** ** | **14.9**                                            |       | 9.9                                                  |       | 51 | ** ** | **59.1** |   | 40.7 |   | 45 |   |
| Cash Expense — RSU & PSU Plan                                                                          | ** ** | **—**                                          |       | —                                               |       | — | ** ** | **20.5** |   | 11.7 |   | 75 |   |
| Cash G&A expenses including RSU & PSU   Plan                                                            | ** ** | **14.9**                                            |       | 9.9                                                  |       | 51 | ** ** | **79.6** |   | 52.4 |   | 52 |   |
| Accrued compensation — RSU & PSU Plan                                                                  | ** ** | **19.8**                                            |       | 3.9                                                  |       | 408 | ** ** | **12.0** |   | (0.1 | ) | — |   |
| Total G&A and incentive compensation expense                                                                     | ** ** | **34.7**                                            |       | 13.8                                                 |       | 151 | ** ** | **91.6** |   | 52.3 |   | 75 |   |
| Total G&A and incentive compensation expense   per boe                                                           | ** ** | **4.45**                                            |       | 2.40                                                 |       | 85 | ** ** | **3.39** |   | 2.26 |   | 50 |   |

 

**Long-Term Incentive Plans — Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan**

 

**Restricted Share Units and Performance Share Units Plan**

The RSU & PSU Plan (formerly referred to as the Whole Unit Plan) is designed to offer each employee, officer and director (the “plan participants”) cash compensation in relation to the value of a specified number of underlying share units. The RSU & PSU Plan consists of Restricted Share Units (“RSUs”) for which the number of units is fixed and will vest over a period of three years and Performance Share Units (“PSUs”) for which the number of units is variable and will vest at the end of three years.

 

Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying share units plus accrued dividends. The cash compensation issued upon vesting of the PSUs is dependent upon the total return performance of ARC compared to its peers. Total return is calculated as a sum of the change in the market price of the common shares in the period plus the amount of dividends in the period. A performance multiplier is applied to the PSUs based on the percentile rank of ARC’s total shareholder return compared to its peers. The performance multiplier ranges from zero, if ARC’s performance ranks in the bottom quartile, to two for top quartile performance.

 

ARC did not make any cash payments under the RSU & PSU Plan in the fourth quarter of 2010.  For the full year 2010, cash RSU & PSU Plan payments totaled $28 million, of which $20.5 million was recorded in G&A with the remaining $7.5 million recorded to operating costs and property, plant and equipment.  The increase in cash RSU & PSU Plan from 2009 to 2010 reflects ARC’s increase in share price and a two times performance multiplier due to ARC’s shares achieving top quartile total returns to its shareholders compared to its selected peer group.  The next cash payment under the RSU & PSU Plan is scheduled to occur in March 2011.

 

A non-cash RSU & PSU Plan expense of $19.8 million was recorded in the fourth quarter of 2010 compared to $3.9 million in 2009. For the full year 2010, a non-cash RSU & PSU Plan expense of $12 million was recorded compared to a recovery of $0.1 million in 2009. The increase in expense for both periods is due to the increase in ARC’s share price and performance multiplier.

 

Table 18 shows the changes to the RSU & PSU Plan during 2010 along with the estimated value upon vesting of the plan as at December 31, 2010:

 

12

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**Table 18**

 
| **RSU & PSU Plan   (units in thousands and $ millions except per unit) ** | ** ** | **Number of    RSUs** | ** ** | **Number of    PSUs** | ** ** | **Total   RSUs and PSUs** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|-------------------------------------|------------|
| Balance, beginning of year                                                                                                                |       | 1,052                           |       | 1,305                           |       | 2,357                               |       |
| Granted                                                                                                                                   |       | 511                             |       | 460                             |       | 971                                 |       |
| Vested                                                                                                                                    |       | (459                            | )          | (321                            | )          | (780                                | )          |
| Forfeited                                                                                                                                 |       | (87                             | )          | (143                            | )          | (230                                | )          |
| Balance, end of year (1)                                                                                                                  |       | 1,017                           |       | 1,301                           |       | 2,318                               |       |
| Estimated dividends                                                                                                                       |       | 74                              |       | 135                             |       | 209                                 |       |
| Estimated units upon vesting after dividends                                                                                              |       | 1,091                           |       | 1,436                           |       | 2,527                               |       |
| Performance multiplier (2)                                                                                                                |       | —                          |       | 1.5                             |       | —                              |       |
| Estimated units upon vesting                                                                                                              |       | 1,091                           |       | 2,091                           |       | 3,182                               |       |
| Share price at December 31, 2010                                                                                                     |       | 25.41                           |       | 25.41                           |       | 25.41                               |       |
| Estimated total value upon vesting ($ millions)                                                                                      |       | 27.7                            |       | 53.1                            |       | 80.8                                |       |

 

----

| (1) | Based   on underlying units before performance multiplier and accrued dividends.                                                                                                                                                                                                                                                                                                 |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | The   performance multiplier only applies to PSUs and was estimated to be 1.5 at   December 31, 2010 based on an average calculation of all outstanding   grants. The performance multiplier is assessed each period end based on   actual results of ARC relative to its peers except during the first year of each   grant where a performance multiplier of 1.0 is used. |

 

The value associated with the RSUs and PSUs is expensed in the statement of income over the vesting period with the expense amount being determined by the share price, accrued dividends and the number of PSUs to be issued on vesting. In periods where substantial share price fluctuation occurs, ARC’s G&A expense is subject to significant volatility.

 

Due to the variability in the future payments under the plan, ARC estimates that between $27.7 million and $100.6 million will be paid out from 2011 through 2013 based on the current share price, accrued dividends and ARC’s market performance relative to its peers.  Table 19 is a summary of the range of future expected payments under the RSU & PSU Plan based on variability of the performance multiplier and units outstanding under the RSU & PSU Plan as at December 31, 2010:

 

**Table 19**

 
| **Value of RSU & PSU Plan as at******** December 31, 2010** | ** ** | **Performance multiplier** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| **(units thousands and $ millions except per unit)**                           | ** ** | **-**                           | ** ** | **1.0** | ** ** | **2.0** | ** ** |
| Estimated units to vest                                                                                           |       |                            |       |   |   |   |   |
| RSUs                                                                                                              |       | 1,091                           |       | 1,091 |   | 1,091 |   |
| PSUs                                                                                                              |       | —                          |       | 1,436 |   | 2,870 |   |
| **Total units****(1)**                                                                                            | ** ** | **1,091**                       | ** ** | **2,527** | ** ** | **3,961** | ** ** |
| Share price (2)                                                                                                   |       | 25.41                           |       | 25.41 |   | 25.41 |   |
| **Value of RSU & PSU Plan   upon vesting**(3)                                                            | ** ** | **27.7**                        | ** ** | **64.2** | ** ** | **100.6** | ** ** |
| 2011                                                                                                              |       | 13.5                            |       | 23.0 |   | 32.5 |   |
| 2012                                                                                                              |       | 10.0                            |       | 25.6 |   | 41.2 |   |
| 2013                                                                                                              |       | 4.2                             |       | 15.6 |   | 26.9 |   |

 

----

| (1) | Includes   additional estimated units to be issued under the RSU & PSU Plan for   accrued dividends.                                                                                                                                                                                                      |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | Values   will fluctuate over the vesting period based on the volatility of the   underlying share price. Assumes a future share price of $25.41.                                                                                                                                                                   |
| (3) | Upon   vesting, a cash payment is made equivalent to the value of the share units or   market price of the underlying common shares. The payment is made on vesting   dates in March and September of each year and, at that time, is   reflected as a reduction of cash flow from operating activities. |

 

13

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**Share Option Plan (“ARC options”)**

On December 15, 2010, ARC shareholders approved a new ARC Share Option Plan.  To date, no ARC options have been granted under this plan.  The maximum shares issuable under this plan shall not exceed 14.2 million shares and is subject to the following terms, subject to modification, by ARC’s Board of Directors:

 
| · | ARC   options will have a term not exceeding seven years;                                                                                                                                              |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | 50   per cent of a grant will vest on each of the fourth and fifth anniversary   grant dates, respectively;                                                                                            |
| · | Grant   price will not be less than the five-day volume weighted average price of   ARC’s shares on the TSX preceding the grant date; and                                                         |
| · | Exercise   price, at the election of the optionholder, will be either the grant price or   the price calculated by the grant price less all dividends paid from the   grant date to the exercise date. |

 

**Deferred Share Unit Plan (“DSU Plan”)**

On December 15, 2010, ARC shareholders approved a new Directors’ DSU Plan.  To date, no deferred share units (“DSUs”) have been granted under this plan. Non-executive directors will no longer receive RSUs but will instead receive DSUs which allows the holder to redeem the DSUs for a cash payment equal to the number of DSUs multiplied by the weighted average trading price of ARC’s shares on the TSX for the five trading days prior to the date of settlement.  DSUs are adjusted for dividends.  Redemption may occur from the date that the holder ceases to be a director of ARC until December 1 in the following calendar year.

 

**Interest and financing charges**

Interest and financing charges increased to $10.5 million in the fourth quarter of 2010 from $5.9 million in 2009.  For the full year 2010, interest and financing charges increased 65 per cent from $25.7 million in 2009 to $42.5 million in 2010 as a result of financing charges incurred on the renewal of ARC’s credit facility and with increased debt servicing costs associated with the renewed facility.  As at December 31, 2010, ARC has $803.5 million of long-term debt outstanding, of which $444.5 million is fixed at a weighted average interest rate of 5.8 per cent.  On the remaining $359 million ARC currently pays a floating interest rate based on current market rates plus a credit spread of 225 basis points. Approximately 52 per cent (US$417.8 million) of ARC’s debt outstanding is denominated in U.S. dollars.

 

**Foreign Exchange Gains and Losses**

ARC recorded a gain of $15.1 million in the fourth quarter of 2010 on foreign exchange transactions compared to a gain of $9.7 million in 2009. These amounts include both realized and unrealized foreign exchange gains and losses.

 

Table 20 shows the various components of foreign exchange gains and losses:

 

**Table 20**

 
| **Foreign Exchange Gains/Losses**             | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|---------------------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| **($ millions)**                                   | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Unrealized gain (loss) on U.S. denominated debt         | ** ** | **10.3**                                            |       | 5.7                                                  |       | 81 | ** ** | **(6.0** | **)** | 66.3 |   | (109 | ) |
| Realized gain on U.S. denominated debt                  | ** ** | **4.6**                                             |       | 3.1                                                  |       | 48 | ** ** | **32.9** |   | 2.7 |   | — |   |
| Realized gain (loss) on U.S. denominated   transactions | ** ** | **0.2**                                             |       | 0.9                                                  |       | (78 | ) | **(0.1** | **)** | 1.0 |   | (110 | ) |
| Total foreign exchange gain                             | ** ** | **15.1**                                            |       | 9.7                                                  |       | 56 | ** ** | **26.8** |   | 70.0 |   | (62 | ) |

 

Nominal realized foreign exchange gains and losses arising from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements were recorded during the fourth quarter of 2010.

 

Unrealized foreign exchange gains and losses are due to the revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain or loss impacts net income but does not impact cash flow from operating activities as it is a non-cash item. From September 30, 2010 to December 31, 2010, the Cdn$/US$ exchange rate decreased from 1.03 to 0.99 resulting in an unrealized gain of $15.1 million on U.S. dollar denominated debt.

 

14

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**Taxes**

In the fourth quarter of 2010, a future income tax recovery of $18.4 million was recorded compared to $1.9 million in 2009.  The fourth quarter 2010 recovery is primarily due to an $85.9 million unrealized loss on risk management contracts.

 

The corporate income tax rate applicable to 2010 is 28 per cent, however, ARC and its subsidiaries did not pay any material cash income taxes for the fourth quarter of 2010. Up until December 31, 2010, ARC’s structure was such that both income tax and future tax liabilities were passed onto the unitholders by means of royalty payments made between ARC and the Trust.  With the conversion from a trust structure to a traditional corporate structure effectively completed on December 31, 2010, ARC will be subject to future income taxes and tax liabilities. Current taxes payable by ARC will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures.  As ARC has accumulated $2.4 billion of income tax pools for federal tax purposes, taxable income will be reduced or potentially eliminated for the initial period post-conversion.  Using the current forward commodity price outlook and a modeled future production volume forecast, ARC does not expect to be in a material cash tax-paying position until 2013.  The income tax pools (detailed in Table 21) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.

 

**Table 21**

 
| **Income Tax Pool type** | ** ** | **Cdn$ millions at   December 31, 2010** | ** ** | **Annual deductibility**               | ** ** |
|-----------------------------------------|------------|--------------------------------------------------------------|------------|---------------------------------------------|------------|
| Canadian Oil and Gas Property Expense   |       | 982.5                                                        |       | 10% declining balance                       |       |
| Canadian Development Expense            |       | 504.4                                                        |       | 30% declining balance                       |       |
| Canadian Exploration Expense            |       | 95.5                                                         |       | 100                                         | %          |
| Undepreciated Capital Cost              |       | 619.2                                                        |       | Primarily 25% declining balance             |       |
| Non-Capital Losses                      |       | 183.9                                                        |       | 100                                         | %          |
| Research and Experimental Expenditures  |       | 22.2                                                         |       | 100                                         | %          |
| Other                                   |       | 26.0                                                         |       | Various rates, 7% declining balance to 20%  |       |
| **Total Federal Tax Pools**             | ** ** | **2,433.7**                                                  |       |                                        |       |
| **Additional Alberta Tax Pools**        | ** ** | **177.6**                                                    |       | Various rates, 25% declining balance to100% |       |

 

**Depletion, Depreciation and Accretion of Asset Retirement Obligation**

The depletion, depreciation and accretion (“DD&A”) rate increased slightly to $16.98 per boe in the fourth quarter of 2010 from $16.71 per boe in 2009. For the full year 2010, the DD&A rate increased three per cent from $16.66 per boe in 2009 to $17.08 per boe in 2010.  The increase related primarily to the acquisition of Storm, which added both proved and probable reserves to ARC’s asset base.  ARC, however, only recognizes proved reserves for the purpose of its depletion calculation.  As such, actual depletion expense has increased both in the fourth quarter of 2010 over the fourth quarter of 2009 and the full year of 2010 over the full year of 2009 due to the increase in the DD&A rate as well as an increase in production volumes of 35 per cent and 16 per cent quarter over quarter and year over year, respectively.  In the second quarter of 2010, ARC relocated to a new head office and began depreciating the associated leasehold improvements and construction costs. In previous periods, nominal depreciation had been recognized.

 

A breakdown of the DD&A rate is summarized in Table 22:

 

**Table 22**

 
| **DD&A Rate**                                           | ** ** | **Three Months Ended   December 31** | ** ** | **Twelve Months Ended   December 31** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------------------------|------------|
| **($ millions except per boe amounts)** | ** ** | **2010**                                            | ** ** | **2009**                                             | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Depletion of oil and gas assets (1)                              | ** ** | **128.5**                                           |       | 93.8                                                 |       | 37 | ** ** | **448.1** |   | 377.1 |   | 19 |   |
| Depreciation of fixed assets                                     | ** ** | **1.2**                                             |       | —                                               |       | 100 | ** ** | **3.1** |   | — |   | 100 |   |
| Accretion of asset retirement obligation (2)                     | ** ** | **2.6**                                             |       | 2.3                                                  |       | 13 | ** ** | **9.9** |   | 9.3 |   | 6 |   |
| Total DD&A                                                   | ** ** | **132.3**                                           |       | 96.1                                                 |       | 38 | ** ** | **461.1** |   | 386.4 |   | 19 |   |
| DD&A rate per boe                                            | ** ** | **16.98**                                           |       | 16.71                                                |       | 2 | ** ** | **17.08** |   | 16.66 |   | 3 |   |

 

----

(1)          Includes depletion of the capitalized portion of the asset retirement obligation that was capitalized to the property, plant and equipment balance and is being depleted over the life of the reserves.

(2)          Represents the accretion expense on the asset retirement obligation during the year.

 

15

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**Capital Expenditures and Net Acquisitions**

Capital expenditures, excluding acquisitions and dispositions, totaled $159.1 million in the fourth quarter of 2010 and $590.9 million for the full year 2010.  This amount was incurred on drilling and completions, geological, geophysical, facilities expenditures and undeveloped land.

 

For the full year 2010, $335.3 million was spent on ARC’s resource plays, including $240.3 million for development of the Montney resource play in northeast British Columbia, $42.7 million on undeveloped lands for the Montney resource play, $43 million for the Cardium resource play in Alberta, and $1.7 million on undeveloped lands for the Cardium resource play.  The remaining $197.5 million was spent on ARC’s conventional oil and gas properties, $16.5 million spent on conventional land purchases, $17.5 million on ARC’s enhanced oil recovery initiatives and $24.1 million on leasehold expenditures associated with ARC’s corporate office move. Total capital expenditures are forecast to be $625 million in 2011.

 

A breakdown of capital expenditures and net acquisitions is shown in Table 23:

 

**Table 23**

 
| **Capital Expenditures**                      | ** ** | **Three Months Ended    December 31** | ** ** | **Twelve Months Ended    December 31** | ** ** |
|----------------------------------------------------|------------|-----------------------------------------------------------|------------|------------------------------------------------------------|------------|
| **($ millions)**                              | ** ** | **2010**                                                  | ** ** | **2009**                                                   | ** ** | **% Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% Change** | ** ** |
| Geological and geophysical                         | ** ** | **5.6**                                                   |       | 2.9                                                        |       | 93 | ** ** | **16.0** |   | 13.7 |   | 17 |   |
| Drilling and completions                           | ** ** | **100.4**                                                 |       | 66.2                                                       |       | 52 | ** ** | **358.5** |   | 214.3 |   | 67 |   |
| Plant and facilities                               | ** ** | **42.9**                                                  |       | 35.2                                                       |       | 22 | ** ** | **131.4** |   | 110.0 |   | 19 |   |
| Undeveloped land purchased at crown land sales     | ** ** | **6.9**                                                   |       | 2.1                                                        |       | 229 | ** ** | **60.9** |   | 7.0 |   | — |   |
| Other capital                                      | ** ** | **3.3**                                                   |       | 10.9                                                       |       | (70 | ) | **24.1** |   | 14.6 |   | 65 |   |
| Total capital expenditures before net acquisitions | ** ** | **159.1**                                                 |       | 117.3                                                      |       | 36 | ** ** | **590.9** |   | 359.6 |   | 64 |   |
| Producing property acquisitions (1)                | ** ** | **1.2**                                                   |       | 1.2                                                        |       | — | ** ** | **8.9** |   | 8.2 |   | 9 |   |
| Undeveloped land property acquisitions             | ** ** | **—**                                                |       | 5.8                                                        |       | (100 | ) | **—** |   | 14.5 |   | (100 | ) |
| Producing property dispositions (1)                | ** ** | **(0.4**                                                  | **)**      | —                                                     |       | — | ** ** | **(3.9** | **)** | (37.3 | ) | (90 | ) |
| Undeveloped land property dispositions             | ** ** | **—**                                                |       | (5.9                                                       | )          | (100 | ) | **—** |   | (5.9 | ) | (100 | ) |
| Corporate acquisition (2)                          | ** ** | **—**                                                |       | 178.9                                                      |       | (100 | ) | **652.1** |   | 178.9 |   | 265 |   |
| Total capital expenditures and net acquisitions    | ** ** | **159.9**                                                 |       | 297.3                                                      |       | (46 | ) | **1,248.0** |   | 518.0 |   | 141 |   |

 

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(1)          Value is net of post-closing adjustments.

(2)          Represents total consideration paid for corporate acquisitions.

 

On a regular basis, ARC evaluates its asset portfolio to ensure that all assets still fit our business strategy and may sell assets that do not meet our retention guidelines.  On January 31, 2011, ARC disposed of non-core assets in central Alberta that currently produce approximately 3,400 boe per day (60 per cent gas and 40 per cent liquids) for proceeds of $170 million.

 

Approximately 85 per cent of the $159.1 million capital program in the fourth quarter of 2010 was financed with cash flow from operating activities and proceeds from our Dividend Reinvestment and Optional Cash Payment Program (“DRIP”) compared to 73 per cent in 2009. On a year-to-date basis, ARC has funded 75 per cent of the capital expenditures with cash flow from operating activities and proceeds from DRIP, compared to 73 per cent in 2009.

 

**Table 24**

 

**Source of Funding of Capital Expenditures and Net Acquisitions**

($ millions)

 
| ** **                          | ** ** | **Three Months Ended December 31, 2010** | ** ** | **Three Months Ended December 31, 2009** | ** ** |
|-------------------------------------|------------|-------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                          | ** ** | **Capital    Expenditures**                                  | ** ** | **Net    Acquisitions ****(1)**                         | ** ** | **Total    Expenditures** | ** ** | **Capital    Expenditures** | ** ** | **Net    Acquisitions****(1)** | ** ** | **Total    Expenditures** | ** ** |
| Expenditures                        | ** ** | **159.1**                                                         | ** ** | **0.8**                                                           | ** ** | **159.9** |   | 117.3 |   | 180.0 |   | 297.3 |   |
|                                | ** ** | ** **                                                        | ** ** | ** **                                                        | ** ** | ** ** |   |   |   |   |   |   |   |
| Cash flow from operating activities | ** ** | **70**                                                            | **%**      | **—**                                                        | ** ** | **70** | **%** | 60 | % | — |   | 24 | % |
| Proceeds from DRIP                  | ** ** | **15**                                                            | **%**      | **—**                                                        | ** ** | **15** | **%** | 13 | % | — |   | 5 | % |
| Debt/(excess funding)               | ** ** | **15**                                                            | **%**      | **100**                                                           | **%**      | **15** | **%** | 27 | % | 100 | % | 71 | % |
|                                | ** ** | **100**                                                           | **%**      | **100**                                                           | **%**      | **100** | **%** | 100 | % | 100 | % | 100 | % |

 

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(1)          Includes corporate acquisitions based on total consideration paid.

 

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** **

**Table 24a**

 

**Source of Funding of Capital Expenditures and Net Acquisitions**

($ millions)

 
| ** **                          | ** ** | **Twelve Months Ended December 31, 2010** | ** ** | **Twelve Months Ended December 31, 2009** | ** ** |
|-------------------------------------|------------|--------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                          | ** ** | **Capital    Expenditures**                                   | ** ** | **Net    Acquisitions ****(1)**                          | ** ** | **Total    Expenditures** | ** ** | **Capital    Expenditures** | ** ** | **Net **

**Acquisitions****(1)** | ** ** | **Total    Expenditures** | ** ** |
| Expenditures                        | ** ** | **590.9**                                                          | ** ** | **657.1**                                                          | ** ** | **1,248.0** |   | 359.6 |   | 158.4 |   | 518.0 |   |
|                                | ** ** | ** **                                                         | ** ** | ** **                                                         | ** ** | ** ** |   |   |   |   |   |   |   |
| Cash flow from operating activities | ** ** | **62**                                                             | **%**      | **—**                                                         | ** ** | **30** | **%** | 54 | % | — |   | 38 | % |
| Proceeds from DRIP                  | ** ** | **13**                                                             | **%**      | **—**                                                         | ** ** | **6** | **%** | 19 | % | — |   | 13 | % |
| Proceeds from equity                | ** ** | **—**                                                         | ** ** | **85**                                                             | **%**      | **44** | **%** | — |   | — |   | — |   |
| Debt                                | ** ** | **25**                                                             | **%**      | **15**                                                             | **%**      | **20** | **%** | 27 | % | 100 | % | 49 | % |
|                                | ** ** | **100**                                                            | **%**      | **100**                                                            | **%**      | **100** | **%** | 100 | % | 100 | % | 100 | % |

 

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(1)          Includes corporate acquisitions based on total consideration paid.

 

**Asset Retirement Obligation and Reclamation Fund**

At December 31, 2010, ARC recorded an Asset Retirement Obligation (“ARO”) of $169.1 million ($149.9 million at December 31, 2009) for the future abandonment and reclamation of ARC’s properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property as well as annual inflation factors in order to calculate the undiscounted total future liability. The future liability is then discounted at a weighted average credit adjusted risk free rate of 6.5 per cent.

 

Included in the December 31, 2010 ARO balance is $15 million of additional ARO related to the Storm acquisition, a $1.6 million increase related to development activities, a $0.5 million increase related to the change in estimated future obligations, $9.9 million for accretion expense, and a reduction of $7.8 million for actual abandonment expenditures incurred in 2010.

 

ARC established a restricted reclamation fund to finance obligations specifically associated with the Redwater property in 2005.  Minimum contributions to this fund will be approximately $81 million over the next 45 years.  The balance of this fund totaled $25 million at December 31, 2010, compared to $20.6 million at December 31, 2009.  Under the terms of ARC’s investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities.

 

All investments in the unrestricted fund were withdrawn and applied to outstanding bank debt during the fourth quarter of 2010.  Environmental stewardship is a core value at ARC and abandonment and reclamation activities will continue to be made in the future in a prudent responsible manner with the oversight of the Health, Safety and Environment Committee of the Board. Future abandonment expenditures will be funded entirely from cash flow from operating activities.

 

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** **

**Capitalization, Financial Resources and Liquidity**

A breakdown of ARC’s capital structure is outlined in Table 25, as at December 31, 2010 and December 31, 2009:

 

**Table 25**

 
| **Capital Structure and Liquidity****($ millions except per cent and ratio amounts)** | ** ** | **December 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| Long-term debt                                                                                                                     |       | **803.5**                       |       | 846.1                           |       |
| Working capital deficit (1)                                                                                                             | ** ** | **69.1**                        |       | 56.3                            |       |
| Net debt obligations (2)                                                                                                                | ** ** | **872.6**                       |       | 902.4                           |       |
| Market value of common shares (3)                                                                                                       | ** ** | **7,226.6**                     |       | 4,765.7                         |       |
| Total capitalization (4)                                                                                                                | ** ** | **8,099.2**                     |       | 5,668.1                         |       |
| Net debt as a percentage of total capitalization                                                                                        | ** ** | **10.8**                        | **%**      | 15.9                            | %          |
| Net debt to cash flow from operating activities                                                                                         | ** ** | **1.3**                         |       | 1.8                             |       |

 

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(1)          Working capital deficit is calculated as current liabilities less the current assets as they appear on the Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts and the current portion of future income taxes.

(2)          Net debt is a non-GAAP measure and therefore it may not be comparable with the calculation of similar measures for other entities.

(3)          Calculated using the total common shares outstanding at December 31, 2010 (total trust units outstanding including the total number of trust units issuable for exchangeable shares at December 31, 2009) multiplied by the closing share price of $25.41 for 2010 (closing trust unit price of $19.94 for 2009).

(4)          Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Total capitalization is not intended to represent the total funds from equity and debt received by ARC.

 

At December 31, 2010, ARC had total credit facilities of $1.6 billion with $803.5 million currently drawn resulting in unused credit available of $779.8 million.  On August 3, 2010, ARC signed an agreement to renew its syndicated credit facility for a three-year term, effective August 4, 2010 to August 3, 2013. The renewed facility increases the existing credit facility from $800 million to $1 billion and increases ARC’s total credit facilities from $1.4 billion to $1.6 billion. The credit facilities consist of a banking syndicate of 13 domestic and international banks, senior notes, and a Master Shelf agreement with a U.S. institutional investor.

 

Costs of borrowing under our syndicated credit facility comprise two items: first, the underlying interest rate on Bankers’ Acceptances and Prime Loans (CDN dollar loans) or LIBOR Loans and US Base Rate Loans (U.S. denominated borrowings) and second, ARC’s credit spread.  The credit spread to ARC from the beginning of 2009 to July 2010 ranged between 60 and 70 basis points on all Bankers’ Acceptances and LIBOR Loans. No Prime Loans or US Base Rate Loans were drawn during this period.  Effective August 2010, under the new bank credit facilities, the credit spread increased to 225 basis points for the remainder of 2010.  Future credit spreads to ARC may range from 200 to 350 basis points for Bankers’ Acceptances and LIBOR loans depending on ARC’s debt to cash flow ratio. In addition to paying interest on the outstanding debt under the revolving syndicated credit facility, ARC is charged a standby fee for the amount of the undrawn facility. This standby fee has ranged from 12.5 to 15 basis points from the beginning of 2009 to July 2010 and now ranges from 50 to 87.5 basis points under the renewed facility. These spreads are adjusted on the first day of the third month after each quarter-end date.

 

ARC’s debt agreements contain a number of covenants all of which were met as at December 31, 2010. These agreements are available at www.sedar.com.  The major financial covenants are described below:

 

·                  Long-term debt and letters of credit not to exceed three times annualized net income before non-cash items and interest expense;

·                  Long-term debt, letters of credit, and subordinated debt not to exceed four times annualized net income before non-cash items and interest expense; and

·                  Long-term debt and letters of credit not to exceed 50 per cent of the book value of Shareholders’ equity and long-term debt, letters of credit and subordinated debt.

 

ARC’s long-term strategy is to keep debt at less than two times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels throughout 2009 and 2010 and has positioned ARC to remain well below the debt covenant levels of three times. At the end of 2010, debt to annual cash flow from operating activities was 1.3 times.

 

ARC typically uses three markets to raise capital: equity, bank debt and long-term notes.  All three markets have been accessed by ARC during 2010.  Long-term notes are issued to large institutional investors normally with an average term of five to 10 years. The cost of this debt is based upon two factors: the current rate of long-term government bonds and ARC’s credit spread. ARC’s average interest rate on its outstanding long-term notes is currently 5.8 per cent.

 

18

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ARC expects to finance its 2011 capital program with cash flow from operating activities, proceeds from the DRIP and existing credit capacity. If ARC undertakes any major acquisitions, management would expect to finance the transactions with a combination of debt and equity in a cost effective manner.

 

**Shareholders’ Equity**

On December 31, 2010, ARC converted all outstanding trust units and exchangeable shares into common shares on a one share per trust unit basis.  At December 31, 2010, there were 284.4 million shares issued, an increase of 47.8 million shares over the balance of trust units issued and issuable from December 31, 2009.  This is due primarily to the issuance of 28.4 million trust units and exchangeable shares convertible into trust units in August 2010 in conjunction with the Storm acquisition and the issuance of 13 million trust units from an equity offering that closed in January 2010. The January 2010 equity offering was made concurrent with ARC’s $180 million purchase of properties at Ante Creek, with gross and net proceeds of approximately $252 million and $240 million, respectively.

 

Pursuant to the Arrangement and the conversion from a trust to a corporation, ARC’s deficit on December 31, 2010 was reduced to nil through a reduction of Shareholders’ Capital by $631.3 million.

 

Shareholders electing to reinvest dividends or make optional cash payments to acquire shares from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. In 2010, ARC raised proceeds of $74.4 million and issued 3.7 million trust units pursuant to the DRIP at an average price of $20.16 per share.

 

**Distributions/Dividends**

In the fourth quarter of 2010, ARC declared distributions of $82.9 million ($0.30 per trust unit) compared to distributions of $70.9 million ($0.30 per trust unit) in 2009.  For the full year 2010, ARC declared distributions of $313.5 million ($1.20 per trust unit) compared to distributions of $298.5 million ($1.28 per trust unit) in 2009.

 

Pursuant to the conversion to a corporation, ARC will now pay dividends to its shareholders effective January 1, 2011, with the first dividend payment to be made on February 15, 2011.  ARC continually assesses dividend levels in light of commodity prices, capital expenditure programs and production volumes, to ensure that dividends are in line with the long-term strategy and objectives of ARC as per the following guidelines:

 

·      To maintain a dividend policy that, in normal times, in the opinion of management and the Board of Directors, is sustainable for a minimum period of six months after factoring in the impact of current commodity prices on cash flows. ARC’s objective is to normalize the effect of volatility of commodity prices rather than to pass that volatility onto shareholders in the form of fluctuating monthly dividends.

 

·      To ensure that ARC’s financial flexibility is maintained by a review of ARC’s debt to equity and debt to cash flow from operating activities levels. The use of cash flow from operating activities and proceeds from equity offerings to fund capital development activities reduces the need to use debt to finance these expenditures. In 2010, ARC funded 75 per cent of capital development activities with cash flow from operating activities and DRIP proceeds. Dividends and the actual amount of cash flows withheld to fund ARC’s capital expenditure program is dependent on the commodity price environment and is subject to the approval and discretion of the Board of Directors.

 

The actual amount of future monthly dividends is proposed by management and is subject to the approval and discretion of the Board of Directors. The Board reviews future dividends in conjunction with their review of quarterly financial and operating results.

 

Please refer to ARC’s website at www.arcresources.com for details of the monthly dividends amounts and dividend dates for 2011.

 

**Taxation of Distributions and Dividends**

Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held.  Effective January 1, 2011, ARC will pay dividends to its shareholders.  Dividends from ARC are taxed differently than distributions of the Trust in that dividends do not comprise a return of capital and thus are fully taxable. For a more detailed breakdown, please visit our website at www.arcresources.com.  The following table is a summary of historical distributions paid.

 

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**Table 26**

 
| **Calendar Year** | ** ** | **Distributions** | ** ** | **Taxable Portion** | ** ** | **Return of Capital** | ** ** |
|------------------------|------------|-------------------|------------|--------------------------|------------|---------------------------------|------------|
| 2010 (2)               |       | 1.20              |       | 1.02                     |       | 0.18                            |       |
| 2009                   |       | 1.28              |       | 1.24                     |       | 0.04                            |       |
| 2008                   |       | 2.67              |       | 2.62                     |       | 0.05                            |       |
| 2007                   |       | 2.40              |       | 2.32                     |       | 0.08                            |       |
| 2006(1)                |       | 2.60              |       | 2.55                     |       | 0.05                            |       |
| 2005                   |       | 1.94              |       | 1.90                     |       | 0.04                            |       |
| 2004                   |       | 1.80              |       | 1.69                     |       | 0.11                            |       |
| 2003                   |       | 1.78              |       | 1.51                     |       | 0.27                            |       |
| 2002                   |       | 1.58              |       | 1.07                     |       | 0.51                            |       |
| 2001                   |       | 2.41              |       | 1.64                     |       | 0.77                            |       |
| 2000                   |       | 1.86              |       | 0.84                     |       | 1.02                            |       |
| 1999                   |       | 1.25              |       | 0.26                     |       | 0.99                            |       |
| 1998                   |       | 1.20              |       | 0.12                     |       | 1.08                            |       |
| 1997                   |       | 1.40              |       | 0.31                     |       | 1.09                            |       |
| 1996                   |       | 0.81              |       | —                   |       | 0.81                            |       |
| **Cumulative**         | ** ** | **$**             | **26.18**  | ** **               | **$**      | **19.09**                       | ** ** | **$** | **7.09** | ** ** |
|                        |            |                   |            |                          |            |                                 |            |  |  |  |

 

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(1)          Based on distributions paid and payable in 2006.

(2)          Based on distributions declared at December 31, 2010 and taxable portion of 2010 distributions of 85 per cent.

 

**Environmental Initiatives Impacting ARC**

There are no new material environmental initiatives impacting ARC at this time.

 

**Contractual Obligations and Commitments**

ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC’s cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 27.

 

**Table 27**

 
| ** **                            | ** ** | **Payments Due by Period** | ** ** |
|---------------------------------------|------------|-------------------------------------------|------------|
| **($ millions)**                 | ** ** | **1 year**                           | ** ** | **2—3 years** | ** ** | **4-5 years** | ** ** | **Beyond 5    years** | ** ** | **Total** | ** ** |
| Debt repayments (1)                   |       | 17.0                                      |       | 437.1 |   | 83.0 |   | 266.4 |   | 803.5 |   |
| Interest payments (2)                 |       | 25.8                                      |       | 46.1 |   | 36.4 |   | 52.3 |   | 160.6 |   |
| Reclamation fund contributions (3)    |       | 4.6                                       |       | 8.3 |   | 7.1 |   | 60.8 |   | 80.8 |   |
| Purchase commitments                  |       | 38.7                                      |       | 33.6 |   | 12.8 |   | 9.2 |   | 94.3 |   |
| Transportation commitments            |       | 27.1                                      |       | 46.2 |   | 32.5 |   | 18.2 |   | 124.0 |   |
| Operating leases                      |       | 9.0                                       |       | 18.1 |   | 14.9 |   | 64.7 |   | 106.7 |   |
| Risk management contract premiums (4) |       | 3.6                                       |       | 2.2 |   | — |   | — |   | 5.8 |   |
| Total contractual obligations         |       | 125.8                                     |       | 591.6 |   | 186.7 |   | 471.6 |   | 1,375.7 |   |

 

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(1)          Long-term and short-term debt.

(2)          Fixed interest payments on senior notes.

(3)          Contribution commitments to a restricted reclamation fund associated with the Redwater property.

(4)           Fixed premiums to be paid in future periods on certain commodity risk management contracts.

 

In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 14 of the unaudited Consolidated Financial Statements). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2010 on the balance sheet as part of risk management contracts.

 

ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. ARC’s 2011 capital budget of $625 million has been approved by the Board of Directors. The remaining portion of this commitment, as at December 31, 2010, has not been disclosed in the commitment table (Table 27) as it is of a routine nature and is part of normal course of operations for active oil and gas companies.

 

ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on ARC’s financial position or results of operations and therefore the commitment table (Table 27) does not include any commitments for outstanding litigation and claims.

 

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ARC has certain sales contracts with aggregators whereby the price received by ARC is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table (Table 27) as it is of a routine nature and is part of normal course of operations.

 

**Off Balance Sheet Arrangements**

ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 27), which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as of December 31, 2010.

 

**Critical Accounting Estimates**

ARC has continuously refined and documented its management and internal reporting systems to ensure that accurate, timely, internal and external information is gathered and disseminated.

 

ARC’s financial and operating results incorporate certain estimates including:

 

·                  estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

 

·                  estimated capital expenditures on projects that are in progress;

 

·                  estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that ARC expects to recover in the future;

 

·                  estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;

 

·                  estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and

 

·                  estimated future recoverable value of property, plant and equipment and goodwill.

 

ARC has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

 

ARC’s leadership team’s mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with ARC’s environmental, health and safety policies.

 

**ASSESSMENT OF BUSINESS RISKS**

The ARC management team is focused on long-term strategic planning and has identified the key risks, uncertainties and opportunities associated with ARC’s business that can impact the financial results as follows:

 

**Volatility of Oil and Natural Gas Prices**

ARC’s operational results and financial condition, and therefore the amount of capital expenditures and future dividend payments made to shareholders, will be dependent on the prices received for oil and natural gas production.  Any movement in oil and natural gas prices will have an effect on ARC’s ability to continue with its capital expenditure program and its ability to pay dividends.  Future declines in oil and natural gas prices may result in future declines in, or elimination of, any future dividends. Oil and natural gas prices are determined by economic and, in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, impact prices.  ARC may manage the risk associated with changes in commodity prices by entering into oil or natural gas price derivative contracts. If ARC engages in activities to manage its commodity price exposure, it may forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity derivative contracts activities could expose ARC to losses. To the extent that ARC engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts.

 

**Refinancing and Debt Service**

ARC currently has a $1 billion financial covenant-based syndicated credit facility with thirteen banks.  At the request of ARC, the lenders will review the credit facility each year and determine if they will extend for another year. In the event that the facility is not extended before August 3, 2013, indebtedness under the facility will become repayable at 

 

21

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that date. There is also a risk that the credit facility will not be renewed for the same amount or on the same terms. Any of these events could affect ARC’s ability to fund ongoing operations and make future dividend payments.

 

ARC currently has US$418 million of U.S. denominated long-term debt outstanding which requires annual principal repayments in 2011 through 2022. ARC intends to fund these principal repayments with existing credit facilities. In the event ARC is unable to fund future principal repayments it may impact ARC’s ability to fund its ongoing operations and make future dividend payments.

 

ARC is required to comply with covenants under the credit facility. In the event that ARC does not comply with covenants under the credit facility, ARC’s access to capital could be restricted or repayment could be required. ARC routinely reviews the covenants based on actual and forecast results and has the ability to make changes to its development plans and/or dividend policy to comply with covenants under the credit facility. If ARC becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on such assets of ARC or sell the working interests.

 

**Operational Matters**

The operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to operating subsidiaries of ARC and possible liability to third parties. ARC maintains liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. ARC may become liable for damages arising from such events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will reduce dividend payments to shareholders.

 

Continuing production from a property, and to some extent the marketing of production there from, are largely dependent upon the ability of the operator of the property. Approximately 17 per cent of ARC’s production is operated by third parties. ARC has limited ability to influence costs on partner operated properties. Operating costs on most properties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, ARC’s revenue from such property may be reduced. Payments from production generally flow through the operator and there is a risk of delayed payment, or non-payment and additional expense in recovering such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of ARC to certain properties. A reduction of future dividend payments to shareholders could result under such circumstances.

 

**Reserves Estimates**

The reserves and recovery information contained in ARC’s independent reserves evaluation is only an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserves evaluator. The reserves report was prepared using certain commodity price assumptions. If lower prices for crude oil, natural gas liquids and natural gas are realized by ARC and substituted for the price assumptions utilized in those reserves reports, the present value of estimated future net cash flows for ARC’s reserves as well as the amount of ARC’s reserves would be reduced and the reduction could be significant.

 

**Depletion of Reserves and Maintenance of Dividend**

ARC’s future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on ARC’s success in exploiting its reserves base and acquiring additional reserves. Without reserves additions through acquisition or development activities, ARC’s reserves and production will decline over time as the oil and natural gas reserves are produced out.  There can be no assurance that ARC will make sufficient capital expenditures to maintain production at current levels nor, as a consequence, that the amount of dividends by ARC to shareholders can be maintained at current levels. There can be no assurance that ARC will be successful in developing or acquiring additional reserves on terms that meet ARC’s investment objectives.

 

**Counterparty Risk**

ARC assumes customer credit risk associated with oil and gas sales, financial hedging transactions and joint venture participants.  In the event that ARC’s counterparties default on payments to ARC, cash flows will be impacted and dividend payments to shareholders may be impacted.  ARC has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and gas sales, financial hedging transactions and joint venture participants. A diversified sales customer base is maintained and exposure to individual entities is reviewed on a regular basis.

 

**Variations in Interest Rates and Foreign Exchange Rates**

Variations in interest rates could result in an increase in the amount ARC pays to service debt. World oil prices are quoted in U.S. dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar

exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact ARC’s net production revenue. Volatility in interest rates and the Canadian dollar may affect future cash flow from operations and reduce funds available for both dividends and capital expenditures.  ARC may initiate certain 

 

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derivative contracts to attempt to mitigate these risks. To the extent that ARC engages in risk management activities related to foreign exchange rates, it will be subject to credit risk associated with counterparties with which it contracts. An increase in Canadian/U.S. exchange rates may impact future dividend payments to shareholders and the value of ARC’s reserves as determined by independent evaluators.

 

**Changes in Income Tax Legislation**

In the future, income tax laws or other laws may be changed or interpreted in a manner that adversely affects ARC or its shareholders.  Tax authorities having jurisdiction over ARC or its shareholders may disagree with how ARC calculates its income for tax purposes to the detriment of ARC and its shareholders.

 

**Changes in Government Royalty Legislation**

Provincial programs related to the oil and natural gas industry may change in a manner that adversely impacts shareholders.  ARC currently operates in British Columbia, Alberta, Saskatchewan and Manitoba, all of which have different royalty programs that could be revised at any time. Future amendments to royalty programs in any of ARC’s operating jurisdictions could result in reduced cash flow and reduced dividend payments to shareholders.

 

**Acquisitions**

The price paid for acquisitions is based on engineering and economic estimates of the potential reserves made by independent engineers modified to reflect the technical views of management. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil, natural gas, natural gas liquids and sulphur, future prices of oil, natural gas, natural gas liquids and sulphur and operating costs, future capital expenditures and royalties and other government levies that will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and ARC. In particular, changes in the prices of and markets for oil, natural gas, natural gas liquids and sulphur from those anticipated at the time of making such assessments will affect the amount of future dividends and the value of the shares. In addition, all such estimates involve a measure of geological and engineering uncertainty that could result in lower production and reserves than attributed to the working interests. Actual reserves could vary materially from these estimates. Consequently, the reserves acquired may be less than expected, which could adversely impact cash flow and dividends to shareholders.

 

**Environmental Concerns and Impact on Enhanced Oil Recovery Projects**

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of ARC or its working interests. Such legislation may be changed to impose higher standards and potentially more costly obligations on ARC.   Furthermore, management believes the federal political parties appear to favor new programs for environmental laws and regulation, particularly in relation to the reduction of emissions, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which ARC cannot meet.  Financial penalties or charges could be incurred as a result of the failure to meet such targets.  In particular there is uncertainty regarding the Federal Government’s Regulatory Framework for Air Emissions (“Framework”), as issued under the Canadian Environmental Protection Act.

 

Additionally, the potential impact on ARC’s operations and business of the Framework, with respect to instituting reductions of greenhouse gases, is not possible to quantify at this time as specific measures for meeting Canada’s commitments have not been developed. Currently, companies are permitted to emit CO2 into the atmosphere with no requirement to capture and re-inject the emissions. In order for ARC to carry out its enhanced oil recovery program it is necessary to obtain CO2 at a cost effective rate. Given that companies are not forced to capture their emissions, the infrastructure has not been put in place to facilitate this process. Without any additional provisions from the government, the economic parameters of ARC’s enhanced oil recovery programs would be limited.

 

ARC has established a reclamation fund (the “Redwater fund”) for the purpose of funding future environmental and reclamation obligations at its Redwater property.  For ARC’s other properties, future environmental and reclamation obligations will be funded with cash flow in future periods.  Contributions to the Redwater fund are based on current estimates and there can be no assurances that ARC will be able to satisfy its actual Redwater future environmental and reclamation obligations with the balance of the fund.  Actual future environmental and reclamation expenditures could differ significantly from estimated amounts, therefore future cash flows and dividend payments to shareholders may be negatively impacted in future periods.

 

**PROJECT RISKS**

ARC manages a variety of small and large projects and plans to spend $625 million on capital projects throughout 2011.  Project delays may impact expected revenues from operations.  Significant project cost overruns could make a project uneconomic.  Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:

 

·                  availability of processing capacity;

·                  availability and proximity of pipeline capacity;

 

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·                  availability of storage capacity;

·                  supply of and demand for oil and natural gas;

·                  availability of alternative fuel sources;

·                  effects of inclement weather;

·                  availability of drilling and related equipment;

·                  unexpected cost increases;

·                  accidental events;

·                  changes in regulations;

·                  availability and productivity of skilled labour; and

·                  regulation of the oil and natural gas industry by various levels of government and governmental agencies.

 

Because of these factors, ARC could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that ARC produces.

 

**Disclosure Controls and Procedures**

As of December 31, 2010, an internal evaluation was carried out of the effectiveness of ARC’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that ARC files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by ARC in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to ARC’s management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.

 

**Internal Control over Financial Reporting**

Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Management has assessed the effectiveness of ARC’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. The assessment was based on the framework in *Internal Control — Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Management concluded that ARC’s internal control over financial reporting was effective as of December 31, 2010. The effectiveness of ARC’s internal control over financial reporting as of December 31, 2010 has been audited by Deloitte & Touche LLP, as reflected in their report for 2010.  No changes were made to ARC’s internal control over financial reporting during the year ending December 31, 2010, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

 

**Financial Reporting Update**

* *

*New Accounting Standards Adopted*

In 2010, ARC early adopted CICA Handbook Section 1582 “Business Combinations”, which replaces Section 1581 of the same name. Under this standard, the purchase price of a business combination is based on the fair value of consideration exchanged at the acquisition date and any contingent consideration of the acquisition is to be recognized at fair value at the acquisition date and subsequently re-measured at fair value with changes recorded through earnings each period until settled. In addition, this new guidance generally requires all transaction costs to be expensed through the income statement and any negative goodwill is required to be recognized immediately into earnings.  This standard has been applied prospectively to record ARC’s business combination with Storm.

 

In accordance with the transitional provisions contained within CICA Handbook Section 1582, ARC has, at the same time as its adoption of Section 1582, adopted CICA Handbook Sections 1601 and 1602, which together replace CICA Handbook Section 1600, “Consolidated Financial Statements”, as described below:

 

Section 1601 “Consolidated Financial Statements” establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard did not have any impact on ARC’s consolidated financial statements.

 

Section 1602 “Non-Controlling Interests” establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. Upon adoption of this standard, ARC has reclassified its non-controlling interest to equity on its consolidated balance sheet and presented

 

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its net income and other comprehensive income attributable to itself and its non-controlling interest on a retrospective basis.

 

The above CICA Handbook Sections are converged with International Financial Reporting Standards.

 

*International Financial Reporting Standards (“IFRS”)*

In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by ARC for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

 

ARC commenced the process to transition its financial statements from current Canadian GAAP to IFRS in 2008 and has progressed towards completion during 2009 and 2010. ARC’s project consists of three key phases: the scoping and diagnostic phase, the impact analysis and evaluation phase and the implementation phase.

 

·                  Scoping and diagnostic phase — this phase involves performing a high level impact analysis to identify areas that may be affected by the transition to IFRS.  The results of this analysis were given a priority ranking according to their complexity and the amount of time required to assess the impact of changes in transitioning to IFRS.

 

·                  Impact analysis and evaluation phase — during this phase, items identified in the diagnostic were addressed according to the priority ranking assigned to them.  ARC conducted analysis of policy choices allowed under IFRS and their impact to the financial statements.  Additionally, certain potential differences were further investigated to assess if there was any broader impact to ARC’s debt agreements, compensation arrangements or management reporting systems.  The impact analysis and evaluation phase was concluded with the Audit Committee of the Board of Directors reviewing and approving all accounting policies proposed by management.

 

·                  Implementation phase — involved implementation of all changes approved in the impact analysis and evaluation phase, included some changes to existing information systems, the creation of some new business processes, the modification of some existing debt agreements and training of staff impacted by the conversion.

 

Since its inception, the project has been led by internal staff within the financial reporting group with sponsorship from the management team. ARC has effectively completed all phases of its IFRS transition project and continues to review its draft IFRS financial statements and disclosures for completeness and quality assurance.  The Audit Committee has approved ARC’s IFRS accounting policy selections that have been presented by management to date as disclosed herein.

 

**First Time Adoption of IFRS**

Most adjustments required on transition to IFRS will be made retrospectively against opening retained earnings as of the date of the first comparative balance sheet presented, based on standards applicable at that time.  IFRS 1 provides entities adopting IFRS for the first time with certain optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS. Management has analyzed the various accounting policy choices available under IFRS 1 and has implemented those determined to be the most appropriate for ARC.  Accordingly, it has applied the following IFRS 1 exemptions in its IFRS opening balance sheet:

 

·                  Property, Plant and Equipment (“PP&E”) — IFRS 1 provides an option to entities such as ARC who follow the full cost accounting guideline under Canadian GAAP to value their oil and gas PP&E on the date of transition to IFRS at its deemed cost, defined as the carrying value assigned to these assets under Canadian GAAP at the date of transition, January 1, 2010.  Under IFRS, ARC’s PP&E must be divided into multiple cash generating units (CGUs), which is unlike full cost accounting where all oil and gas assets are accumulated into one cost centre. The deemed cost of ARC’s oil and gas PP&E has been allocated to seven CGUs based on ARC’s proved plus probable reserve values at January 1, 2010.  These CGUs are aligned with the major geographic regions in which ARC operates and could change in the future as a result of significant acquisition or disposition activity.

 

·                  Business Combinations — IFRS 1 provides an optional exemption to the requirement to retrospectively restate any business combinations that have previously been recorded under Canadian GAAP.  Accordingly, ARC will not be recording any adjustments to retrospectively restate any of its business combinations that have occurred prior to January 1, 2010.

 

The following is a listing of key areas where accounting policies differ and where accounting policy decisions are necessary that will impact our reported financial position and results of operations:

 

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·                  Re-classification of Exploration and Evaluation (“E&E”) expenditures from PP&E — Upon transition to IFRS, ARC will reclassify all E&E expenditures that are currently recognized as PP&E on the Consolidated Balance Sheets. This consists of the carrying value of certain undeveloped land that relates to exploration properties. E&E assets will not be amortized and must be assessed for impairment when indicators suggest the possibility of impairment as well as upon transition to PP&E.  Management has identified approximately $23 million of its property, plant and equipment that meets the criteria to be classified as E&E in the opening balance sheet prepared under IFRS as at January 1, 2010.

 

·                  Calculation of depletion expense for PP&E assets — Upon transition to IFRS, ARC has the option to calculate depletion using a reserve base of proved reserves or both proved plus probable reserves, as compared to the Canadian GAAP method of calculating depletion using proved reserves only.  ARC plans to determine its depletion expense using proved plus probable reserves as its depletion base.  Accordingly, ARC expects that its depletion expense for the year ended December 31, 2010 would be reduced by approximately $2.69 per boe of production or approximately $72.6 million as compared to its current calculation under Canadian GAAP.

 

·                  Impairment of PP&E assets — Canadian GAAP generally uses a two-step approach to impairment testing;  first comparing asset carrying values with undiscounted future cash flows to determine whether an impairment exists, and then measuring impairment by comparing asset carrying values to their fair value (which is calculated using discounted cash flows).  Under Canadian GAAP, ARC includes all assets in one impairment test.

 

IFRS uses a one-step approach for testing and measuring impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use.  Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP resulting in impairment testing being done at the CGU level.

 

These differences may potentially result in impairment charges where the carrying value of assets were previously supported under Canadian GAAP by consolidated undiscounted cash flows, but could not be supported by cash flows determined on a more granular discounted basis.

 

At January 1, 2010 impairment tests were performed in accordance with IFRS and no impairment was identified.

 

·                  Asset retirement obligation — Under IFRS, ARC is required to revalue its entire liability for asset retirement costs at each balance sheet date using a current liability-specific discount rate, which can generally be interpreted to mean the current risk-free rate of interest.  Under Canadian GAAP, obligations are discounted using a credit-adjusted risk-free rate and, once recorded, the asset retirement obligation is not adjusted for future changes in discount rates. At January 1, 2010 ARC’s total of its asset retirement obligations will increase $148.2 million to $298.1 million as the liability is revalued to reflect the estimated risk free rate of interest at that time of 4.08%.  As a result of this change, ARC’s deferred tax liability is decreased by $36.9 million and the net offset is recorded as a reduction to deficit.

 

·                  Exchangeable shares — Under IFRS, ARC’s exchangeable shares meet the criteria to be considered a puttable financial instrument and are classified as a current financial liability. They will be recorded on the statement of financial position at their fair value with any changes being recorded in the statement of comprehensive income. At January 1, 2010, ARC’s current liability associated with exchangeable shares under IFRS is $47.2 million.  Under Canadian GAAP, exchangeable shares are classified as non-controlling interest and measured using the equity method.

 

·                  Deferred taxes — Under IFRS, entities that are subject to different tax rates on distributed and undistributed income must calculate deferred taxes using the undistributed profits rate, which is the higher of the two.  Canadian GAAP requires each individual tax rate to be applied to distributed and undistributed profits, respectively.  As a result of using the undistributed profits rate, ARC will record a reduction in its deferred tax liability of $29.8 million upon transition to IFRS, with the offset recorded as a reduction to deficit.

 

Table 28 summarizes ARC’s January 1, 2010 balance sheet under Canadian GAAP and the transitional entries required to present the opening balance sheet under IFRS. ARC has not yet prepared a full set of annual financial statements under IFRS, therefore, amounts are unaudited.

 

**Table 28**

 
| **(Cdn$ millions)**         | ** ** | **Canadian GAAP** | ** ** | **IFRS Adjustments** | ** ** | **IFRS**    | ** ** |
|----------------------------------|------------|------------------------|------------|---------------------------|------------|-------------|------------|
| Current assets                   |       | 147.1                  |       | (7.1                      | )          | 140.0       |       |
| Long-term assets                 |       | 3,767.4                |       | —                    |       | 3,767.4     |       |
| **Total assets**                 | ** ** | **3,914.5**            | ** ** | **(7.1**                  | **)**      | **3,907.4** | ** ** |
| Current liabilities              |       | 203.3                  |       | 47.2                      |       | 250.5       |       |
| Long-term liabilities            |       | 1,336.8                |       | 74.4                      |       | 1,411.2     |       |
| Equity                           |       | 2,374.4                |       | (128.7                    | )          | 2,245.7     |       |
| **Total liabilities and equity** | ** ** | **3,914.5**            | ** ** | **(7.1**                  | **)**      | **3,907.4** | ** ** |

 

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In addition to accounting policy differences, ARC’s transition to IFRS is expected to impact its internal controls over financial reporting, disclosure controls and procedures, certain of ARC’s business activities and IT systems as follows:

 

·                  Internal controls over financial reporting (“ICFR”) — ARC is currently in the process of reviewing its ICFR documentation and is identifying instances where controls must be amended or added in order to address the accounting policy changes required under IFRS.  No material changes in control procedures are expected as a result of transition to IFRS.

 

·                  Disclosure controls and procedures — ARC has assessed the impact of transition to IFRS on its disclosure controls and procedures and has not identified any material changes required in its control environment. It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP. Management is currently drafting its IFRS note disclosure in accordance with current IFRS standards and continues to monitor requirements put forth by the IASB in discussion papers and exposure drafts for future disclosure requirements. Throughout the transition process, ARC has carefully considered its stakeholders’ information requirements and will continue to ensure that adequate and timely information is provided to meet these needs.

 

·                  Business activities — Management has been cognizant of the upcoming transition to IFRS, and as such, has worked with its counterparties and lenders to ensure that any agreements that contain references to Canadian GAAP financial statements are modified to allow for IFRS statements. Based on the changes to ARC’s accounting policies, no issues are expected to arise with the existing wording of debt covenants and related agreements as a result of the conversion to IFRS. During the 2010 quarterly meetings held with its lenders, ARC has provided an update on IFRS as it relates to ARC so that management could adequately address any potential issues prior to finalizing its IFRS accounting policy choices.

 

·                  IT systems — ARC has completed the accounting system updates required in order to prepare for IFRS reporting. The modifications were not significant, however, deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&E and E&E expenditures at a more granular level of detail for IFRS reporting.

 

**Non-GAAP Measures**

Management uses certain key performance indicators (“KPIs”) and industry benchmarks such as operating income, operating netbacks (“netbacks”), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, normalized reserves per share and production per share, normalized dividend adjusted reserves per share and production per share, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability for ARC and provide investors with information that is commonly used by other oil and gas companies. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

 

**Forward-looking Information and Statements**

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “strategy” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: all of the matters under the heading “2010 and 2011 Guidance and Financial Highlights” which contains guidance for 2011, the future expenditure plans and strategy for 2011 and expected production and operations under the heading “Production”, the expectations regarding the pricing of natural gas for 2011 under the heading “Commodity Prices Prior to Hedging”, the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia, the expected provincial royalty rates for 2011 under various commodity pricing outlooks for 2011 under the heading “Operating Netbacks”, the estimated future payments under the RSU & PSU Plan under the heading “Long-term Incentive Plans — Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan”, the estimate of ARC as to when it expects to be in a material cash tax-paying position under the heading “Taxes”, the information as to total capital expenditures forecasted for 2011 under the heading “Capital Expenditures and Net Acquisitions”, the information relating to financing the 2011 capital expenditures under the heading: “Capitalization, Financial Resources and Liquidity”, ARC’s estimates of normal course obligations under the heading “Contractual Obligations and Commitments”, the 

 

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expectations related to the transition from Canadian GAAP to IFRS under the heading “Financial Reporting Update” and “First Time Adoption of IFRS”, and a number of other matters, including the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.

 

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC’s reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC’s products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC’s properties, increased debt levels or debt service requirements; inaccurate estimation of ARC’s oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC’s public disclosure documents (including, without limitation, those risks identified in this MD&A and in ARC’s Annual Information Form).

 

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

 

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**ANNUAL HISTORICAL REVIEW**

 
| **For the year ended December 31   (Cdn $ millions, except per share amounts)** | ** ** | **2010**    | ** ** | **2009**   | ** ** | **2008** | ** ** | **2007**   | ** ** | **2006** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------|------------|-------------|------------|------------|------------|----------|------------|------------|------------|----------|------------|
| **FINANCIAL**                                                                                                                          | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Revenue before royalties                                                                                                               | ** ** | **1,213.7** |       | 978.2      |       | 1,706.4  |       | 1,251.6    |       | 1,230.5  |       |
| Per share (1)                                                                                                                          | ** ** | **4.59**    |       | 4.16       |       | 7.90     |       | 5.95       |       | 6.02     |       |
| Cash flow from operating activities (2)                                                                                                | ** ** | **673.9**   |       | 497.4      |       | 944.4    |       | 704.9      |       | 734.0    |       |
| Per share (1)                                                                                                                          | ** ** | **2.55**    |       | 2.11       |       | 4.37     |       | 3.35       |       | 3.59     |       |
| Net income                                                                                                                             | ** ** | **260.8**   |       | 225.1      |       | 539.9    |       | 502.1      |       | 466.7    |       |
| Per share (1)                                                                                                                          | ** ** | **0.99**    |       | 0.96       |       | 2.50     |       | 2.39       |       | 2.27     |       |
| Operating income (3)                                                                                                                   | ** ** | **244.2**   |       | 181.2      |       | 557.0    |       | 495.6      |       | 475.5    |       |
| Per share (1)                                                                                                                          | ** ** | **0.92**    |       | 0.77       |       | 2.58     |       | 2.36       |       | 2.32     |       |
| Distributions                                                                                                                          | ** ** | **313.5**   |       | 298.5      |       | 570.0    |       | 498.0      |       | 484.2    |       |
| Per unit (1)                                                                                                                           | ** ** | **1.20**    |       | 1.28       |       | 2.67     |       | 2.40       |       | 2.40     |       |
| Total assets                                                                                                                           | ** ** | **4,946.5** |       | 3,914.5    |       | 3,766.7  |       | 3,533.0    |       | 3,479.0  |       |
| Total liabilities                                                                                                                      | ** ** | **1,752.1** |       | 1,540.1    |       | 1,624.6  |       | 1,491.3    |       | 1,550.6  |       |
| Net debt outstanding (4)                                                                                                               | ** ** | **872.7**   |       | 902.4      |       | 961.9    |       | 752.7      |       | 739.1    |       |
| Weighted average shares (millions) (5)                                                                                                 | ** ** | **264.2**   |       | 235.4      |       | 216.1    |       | 210.4      |       | 205.1    |       |
| Shares outstanding and issuable (millions)                                                                                             | ** ** | **284.4**   |       | 239.0      |       | 219.2    |       | 213.2      |       | 207.2    |       |
| **CAPITAL EXPENDITURES**                                                                                                               | ** ** | ** **  |       |       |       |     | ** ** | ** ** |       |     |       |
| Geological and geophysical                                                                                                             | ** ** | **16.0**    |       | 13.7       |       | 27.1     |       | 14.9       |       | 11.4     |       |
| Land                                                                                                                                   | ** ** | **60.9**    |       | 7.0        |       | 122.4    |       | 77.5       |       | 32.4     |       |
| Drilling and completions                                                                                                               | ** ** | **358.5**   |       | 214.3      |       | 305.4    |       | 229.5      |       | 240.5    |       |
| Plant and facilities                                                                                                                   | ** ** | **131.4**   |       | 110.0      |       | 90.4     |       | 72.1       |       | 77.6     |       |
| Other capital                                                                                                                          | ** ** | **24.1**    |       | 14.6       |       | 3.3      |       | 3.2        |       | 2.6      |       |
| Total capital expenditures                                                                                                             | ** ** | **590.9**   |       | 359.6      |       | 548.6    |       | 397.2      |       | 364.5    |       |
| Property acquisitions (dispositions), net                                                                                              | ** ** | **5.0**     |       | (20.5      | )          | 51.0     |       | 42.5       |       | 115.2    |       |
| Corporate acquisitions (6)                                                                                                             | ** ** | **652.1**   |       | 178.9      |       | —   |       | —     |       | 16.6     |       |
| Total capital expenditures and net acquisitions                                                                                        | ** ** | **1,248.0** |       | 518.0      |       | 599.6    |       | 439.7      |       | 496.3    |       |
| **OPERATING**                                                                                                                          | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Production                                                                                                                             | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Crude oil (bbl/d)                                                                                                                      | ** ** | **27,341**  |       | 27,509     |       | 28,513   |       | 28,682     |       | 29,042   |       |
| Natural gas (mmcf/d)                                                                                                                   | ** ** | **254.2**   |       | 194.0      |       | 196.5    |       | 180.1      |       | 179.1    |       |
| Natural gas liquids (bbl/d)                                                                                                            | ** ** | **4,245**   |       | 3,689      |       | 3,861    |       | 4,027      |       | 4,170    |       |
| Total (boe per day 6:1)                                                                                                                | ** ** | **73,954**  |       | 63,538     |       | 65,126   |       | 62,723     |       | 63,056   |       |
| Average prices                                                                                                                         | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Crude oil ($/bbl)                                                                                                                      | ** ** | **73.85**   |       | 62.24      |       | 94.20    |       | 69.24      |       | 65.26    |       |
| Natural gas ($/mcf)                                                                                                                    | ** ** | **4.21**    |       | 4.18       |       | 8.58     |       | 6.75       |       | 6.97     |       |
| Natural gas liquids ($/bbl)                                                                                                            | ** ** | **53.98**   |       | 40.67      |       | 69.71    |       | 54.79      |       | 52.63    |       |
| Oil equivalent ($/boe)                                                                                                                 | ** ** | **44.88**   |       | 42.07      |       | 71.25    |       | 54.54      |       | 53.33    |       |
| **RESERVES**                                                                                                                           | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| (company interest) (7)                                                                                                                 | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Proved plus probable reserves                                                                                                          | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| Crude oil and NGL (mbbl)                                                                                                               | ** ** | **166,553** |       | 153,413    |       | 153,020  |       | 158,341    |       | 162,193  |       |
| Natural gas (bcf)                                                                                                                      | ** ** | **1,925.2** |       | 1,353.2    |       | 1,012.2  |       | 768.2      |       | 743.6    |       |
| Total (mboe)                                                                                                                           | ** ** | **487,418** |       | 378,953    |       | 321,723  |       | 286,370    |       | 286,125  |       |
| **TRADING STATISTICS**                                                                                                                 | ** ** | ** **  | ** ** | ** ** |       |     | ** ** | ** ** |       |     |       |
| (Cdn$, except volumes) based on intra-day trading                                                                                      | ** ** | ** **  |       |       |       |     |       |       |       |     |       |
| High                                                                                                                                   | ** ** | **26.04**   |       | 21.89      |       | 33.95    |       | 23.86      |       | 30.74    |       |
| Low                                                                                                                                    | ** ** | **18.77**   |       | 11.73      |       | 15.01    |       | 18.90      |       | 19.20    |       |
| Close                                                                                                                                  | ** ** | **25.41**   |       | 19.94      |       | 20.10    |       | 20.40      |       | 22.30    |       |
| Average daily volume (thousands)                                                                                                       | ** ** | **1,197**   |       | 1,057      |       | 975      |       | 597        |       | 706      |       |

 

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(1)             Per share amounts (with the exception of per unit distributions which are based on the number of trust units outstanding at each distribution record date) are based on diluted common shares.

(2)             This is a GAAP measure and a change from the non-GAAP measure reported in prior quarters. Refer to non-GAAP section.

(3)             Operating income is a non-GAAP measure and is calculated using net income less significant one-time items and items that are not indicative of operating performance.

(4)             Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes.

(5)             Diluted common shares.

(6)             Represents total consideration for corporate acquisitions including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition.

(7)             Company interest reserves are the gross interest reserves plus the royalty interest prior to the deduction of royalty burdens.

 

29

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**QUARTERLY HISTORICAL REVIEW**

 
| **(Cdn $ millions, except per** | ** ** | **2010** | ** ** | **2009** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| **share amounts)**                             | ** ** | **Q4**   | ** ** | **Q3**   | ** ** | **Q2** | ** ** | **Q1** | ** ** | **Q4** | ** ** | **Q3** | ** ** | **Q2** | ** ** | **Q1** | ** ** |
| **FINANCIAL**                                       |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenue before royalties                            |       | 329.3    |       | 293.6    |       | 276.7 |   | 314.1 |   | 278.6 |   | 239.2 |   | 235.2 |   | 225.2 |   |
| Per share (1)                                       |       | 1.16     |       | 1.10     |       | 1.09 |   | 1.25 |   | 1.17 |   | 1.01 |   | 0.99 |   | 0.98 |   |
| Cash flow from operating activities                 |       | 186.2    |       | 166.2    |       | 162.8 |   | 158.7 |   | 143.2 |   | 125.6 |   | 104.3 |   | 124.3 |   |
| Per share (1)                                       |       | 0.66     |       | 0.62     |       | 0.64 |   | 0.63 |   | 0.60 |   | 0.53 |   | 0.44 |   | 0.54 |   |
| Net income                                          |       | (6.3     | )          | 81.0     |       | 45.4 |   | 140.7 |   | 66.2 |   | 69.6 |   | 66.8 |   | 22.5 |   |
| Per share (1)                                       |       | (0.01    | )          | 0.30     |       | 0.18 |   | 0.56 |   | 0.28 |   | 0.29 |   | 0.28 |   | 0.10 |   |
| Operating income (2)                                |       | 50.4     |       | 53.0     |       | 55.8 |   | 84.9 |   | 61.7 |   | 45.8 |   | 35.3 |   | 38.3 |   |
| Per share (1)                                       |       | 0.18     |       | 0.20     |       | 0.22 |   | 0.34 |   | 0.26 |   | 0.19 |   | 0.15 |   | 0.17 |   |
| Distributions                                       |       | 82.8     |       | 80.3     |       | 75.3 |   | 75.0 |   | 70.9 |   | 70.6 |   | 75.0 |   | 82.0 |   |
| Per unit (1)                                        |       | 0.30     |       | 0.30     |       | 0.30 |   | 0.30 |   | 0.30 |   | 0.30 |   | 0.32 |   | 0.36 |   |
| Total assets                                        |       | 4,946.5  |       | 4,948.6  |       | 4,068.5 |   | 4,020.1 |   | 3,914.5 |   | 3,642.9 |   | 3,672.5 |   | 3,733.1 |   |
| Total liabilities                                   |       | 1,751.1  |       | 1,689.0  |       | 1,384.3 |   | 1,322.4 |   | 1,540.1 |   | 1,278.4 |   | 1,323.1 |   | 1,392.1 |   |
| Net debt outstanding (3)                            |       | 872.6    |       | 871.1    |       | 728.8 |   | 677.8 |   | 902.4 |   | 705.4 |   | 737.6 |   | 781.5 |   |
| Weighted average shares (4)                         |       | 283.7    |       | 268.0    |       | 253.2 |   | 251.8 |   | 238.5 |   | 237.7 |   | 236.6 |   | 228.9 |   |
| Shares outstanding and issuable                     |       | 284.4    |       | 283.1    |       | 253.6 |   | 252.8 |   | 239.0 |   | 238.1 |   | 237.1 |   | 236.0 |   |
| **CAPITAL EXPENDITURES**                            |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Geological and geophysical                          |       | 5.6      |       | 0.2      |       | 3.6 |   | 6.6 |   | 2.9 |   | 3.0 |   | 5.0 |   | 2.8 |   |
| Land                                                |       | 6.9      |       | 28.6     |       | 21.5 |   | 3.9 |   | 2.0 |   | 4.5 |   | 0.2 |   | 0.2 |   |
| Drilling and completions                            |       | 100.4    |       | 96.0     |       | 84.9 |   | 77.2 |   | 66.1 |   | 61.0 |   | 18.6 |   | 68.5 |   |
| Plant and facilities                                |       | 42.9     |       | 32.1     |       | 26.9 |   | 29.5 |   | 35.3 |   | 26.1 |   | 23.6 |   | 25.1 |   |
| Other capital                                       |       | 3.3      |       | 2.6      |       | 7.1 |   | 11.1 |   | 11.0 |   | 1.6 |   | 1.5 |   | 0.6 |   |
| Total capital expenditures                          |       | 159.1    |       | 159.5    |       | 144.0 |   | 128.3 |   | 117.3 |   | 96.2 |   | 48.9 |   | 97.2 |   |
| Property acquisitions (dispositions), net           |       | 0.8      |       | (2.1     | )          | — |   | 6.3 |   | 1.1 |   | (30.1 | ) | 2.3 |   | 6.2 |   |
| Corporate acquisitions (5)                          |       | —   |       | 652.1    |       | — |   | — |   | 178.9 |   | — |   | — |   | — |   |
| Total capital expenditures and net acquisitions     |       | 159.9    |       | 809.5    |       | 144.0 |   | 134.6 |   | 297.3 |   | 66.1 |   | 51.2 |   | 103.4 |   |
| **OPERATING**                                       |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Production                                          |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Crude oil (bbl/d)                                   |       | 27,417   |       | 26,959   |       | 27,354 |   | 27,640 |   | 27,415 |   | 26,921 |   | 26,917 |   | 28,806 |   |
| Natural gas (mmcf/d)                                |       | 311.5    |       | 275.0    |       | 211.2 |   | 217.9 |   | 189.0 |   | 193.1 |   | 200.2 |   | 193.8 |   |
| Natural gas liquids (bbl/d)                         |       | 5,355    |       | 4,690    |       | 3,655 |   | 3,252 |   | 3,597 |   | 3,717 |   | 3,679 |   | 3,764 |   |
| Total (boe per day 6:1)                             |       | 84,686   |       | 77,483   |       | 66,208 |   | 67,207 |   | 62,520 |   | 62,824 |   | 63,969 |   | 64,872 |   |
| Average prices                                      |       |     |       |     |       |   |   |   |   |   |   |   |   |   | ** ** | ** ** | ** ** |
| Crude oil ($/bbl)                                   |       | 76.08    |       | 71.07    |       | 71.98 |   | 76.26 |   | 72.61 |   | 67.74 |   | 62.74 |   | 46.44 |   |
| Natural gas ($/mcf)                                 |       | 3.83     |       | 3.79     |       | 4.12 |   | 5.42 |   | 4.58 |   | 3.25 |   | 3.73 |   | 5.20 |   |
| Natural gas liquids ($/bbl)                         |       | 55.10    |       | 49.13    |       | 53.02 |   | 60.33 |   | 46.12 |   | 38.92 |   | 38.89 |   | 38.86 |   |
| Oil equivalent ($/boe)                              |       | 42.18    |       | 41.14    |       | 45.82 |   | 51.85 |   | 48.35 |   | 41.31 |   | 40.32 |   | 38.40 |   |
| **TRADING STATISTICS**                              |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| (Cdn$) based on intra-day trading                   |       |     |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| High                                                |       | 26.04    |       | 20.95    |       | 22.33 |   | 22.49 |   | 21.89 |   | 20.20 |   | 19.25 |   | 20.90 |   |
| Low                                                 |       | 20.42    |       | 19.02    |       | 19.20 |   | 19.80 |   | 19.06 |   | 15.48 |   | 14.12 |   | 11.73 |   |
| Close                                               |       | 25.41    |       | 20.55    |       | 19.73 |   | 20.50 |   | 19.94 |   | 20.20 |   | 17.81 |   | 14.15 |   |
| Average daily volume (thousands)                    |       | 1,299    |       | 1,160    |       | 1,043 |   | 1,287 |   | 963 |   | 1,038 |   | 988 |   | 1,240 |   |

 

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(1)   Per share amounts (with the exception of per unit distributions which are based on the number of trust units outstanding at each distribution record date) are based on diluted common shares.

(2)   Operating income is a non-GAAP measure and is calculated using net income less significant one-time items and items that are not indicative of operating performance.

(3)   Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes.

(4)   Diluted common shares.

(5)   Represents total consideration for corporate acquisitions including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition.

 

30

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